UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)
 ýQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2017March 31, 2018

OR

 oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______________________ to _______________________

Commission file number:  001-35245

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SRC ENERGY INC.
(Exact name of registrant as specified in its charter)

COLORADO20-2835920
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)

1675 Broadway, Suite 2600, Denver, CO80202
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (720) 616-4300


Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý   No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such filing). Yes ý  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.


Large accelerated filer  ý
Accelerated filer  o
  
Non-accelerated filer  o   (Do not check if a smaller reporting company)    
Smaller reporting company  o
  
 
Emerging growth company  o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o


Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act):  Yes o No ý

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 201,089,000242,054,875 outstanding shares of common stock as of October 31, 2017.April 30, 2018.


SRC ENERGY INC.

Index

   Page
Part I - FINANCIAL INFORMATION  
    
Item 1.Financial Statements (unaudited)  
    
 Condensed Consolidated Balance Sheets as of September 30, 2017March 31, 2018 and December 31, 20162017 
    
 Condensed Consolidated Statements of Operations for the three and nine months ended September 30,March 31, 2018 and 2017 and 2016 
    
 Condensed Consolidated Statements of Cash Flows for the ninethree months ended September 30,March 31, 2018 and 2017 and 2016 
    
 Notes to Condensed Consolidated Financial Statements 
    
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations 
    
Item 3.Quantitative and Qualitative Disclosures About Market Risk 
    
Item 4.Controls and Procedures 
    
Part II - OTHER INFORMATION  
    
Item 1.Legal Proceedings 
    
Item 1A.Risk Factors 
    
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds 
    
Item 3.Defaults of Senior Securities 
    
Item 4.Mine Safety Disclosures 
    
Item 5.Other Information 
    
Item 6.Exhibits 
    
SIGNATURES 





SRC ENERGY INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands, except share data)


ASSETSSeptember 30, 2017 December 31, 2016March 31, 2018 December 31, 2017
Current assets:      
Cash and cash equivalents$21,325
 $18,615
$71,743
 $48,772
Accounts receivable:      
Oil, natural gas, and NGL sales72,309
 25,728
93,732
 86,013
Trade45,280
 6,805
18,718
 18,134
Commodity derivative assets
 297
Other current assets6,289
 2,739
6,944
 7,116
Total current assets145,203
 54,184
191,137
 160,035
      
Property and equipment:      
Oil and gas properties, full cost method:      
Unproved properties and land, not subject to depletion327,154
 398,547
Proved properties, net of accumulated depletion758,135
 424,082
1,021,725
 970,584
Wells in progress158,192
 81,780
149,214
 106,269
Unproved properties and land, not subject to depletion796,225
 793,669
Oil and gas properties, net1,243,481
 904,409
1,967,164
 1,870,522
Other property and equipment, net6,152
 4,327
5,945
 6,054
Total property and equipment, net1,249,633
 908,736
1,973,109
 1,876,576
Cash held in escrow and other deposits
 18,248
Goodwill40,711
 40,711
40,711
 40,711
Other assets2,359
 2,234
2,049
 2,242
Total assets$1,437,906
 $1,024,113
$2,207,006
 $2,079,564
      
LIABILITIES AND SHAREHOLDERS' EQUITY      
Current liabilities:      
Accounts payable and accrued expenses$134,144
 $52,453
$106,509
 $74,672
Revenue payable58,742
 16,557
77,171
 64,111
Production taxes payable37,017
 17,673
57,720
 52,413
Asset retirement obligations2,738
 2,683
4,180
 3,246
Commodity derivative liabilities786
 2,874
11,574
 7,865
Total current liabilities233,427
 92,240
257,154
 202,307
      
Revolving credit facility150,000
 

 
Notes payable, net of issuance costs76,216
 75,614
538,471
 538,186
Commodity derivative liabilities394
 
Asset retirement obligations33,981
 13,775
25,330
 28,376
Deferred taxes5,811
 
Other liabilities2,268
 1,745
2,329
 2,261
Total liabilities496,286
 183,374
829,095
 771,130
      
Commitments and contingencies (See Note 14)

 

Commitments and contingencies (See Note 15)

 

      
Shareholders' equity:      
Preferred stock - $0.01 par value, 10,000,000 shares authorized: no shares issued and outstanding
 

 
Common stock - $0.001 par value, 300,000,000 shares authorized: 200,909,101 and 200,647,572 shares issued and outstanding as of September 30, 2017 and December 31, 2016, respectively201
 201
Common stock - $0.001 par value, 300,000,000 shares authorized: 241,902,501 and 241,365,522 shares issued and outstanding as of March 31, 2018 and December 31, 2017, respectively242
 241
Additional paid-in capital1,158,317
 1,148,998
1,477,953
 1,474,273
Retained deficit(216,898) (308,460)(100,284) (166,080)
Total shareholders' equity941,620
 840,739
1,377,911
 1,308,434
      
Total liabilities and shareholders' equity$1,437,906
 $1,024,113
$2,207,006
 $2,079,564

The accompanying notes are an integral part of these condensed consolidated financial statements
SRC ENERGY INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited; in thousands, except share and per share data)

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016Three Months Ended March 31,
       2018 2017
Oil, natural gas, and NGL revenues$103,593
 $26,234
 $222,419
 $68,454
$147,233
 $43,790
Sales of purchased oil
 
 1,268
 
Total revenues103,593
 26,234
 223,687
 68,454
          
Expenses:          
Lease operating expenses5,154
 3,819
 13,894
 14,963
7,896
 3,722
Transportation and gathering1,855
 250
Production taxes10,083
 (1,461) 21,013
 2,509
13,443
 1,466
Costs of purchased oil
 
 1,518
 
Depreciation, depletion, and accretion33,740
 9,635
 73,396
 33,001
37,081
 13,229
Full cost ceiling impairment
 25,453
 
 215,223
Unused commitment charge
 205
 669
 505

 669
General and administrative8,484
 8,236
 24,289
 23,199
9,600
 8,200
Total expenses57,461
 45,887
 134,779
 289,400
69,875
 27,536
          
Operating income (loss)46,132
 (19,653) 88,908
 (220,946)
Operating income77,358
 16,254
          
Other income (expense):          
Commodity derivatives gain (loss)(2,383) 407
 2,324
 (3,617)(5,781) 3,379
Interest expense, net of amounts capitalized
 
 
 

 
Interest income16
 11
 47
 176
9
 11
Other income (expense)83
 (1) 385
 3
Other income21
 236
Total other income (expense)(2,284) 417
 2,756
 (3,438)(5,751) 3,626
          
Income (Loss) before income taxes43,848
 (19,236) 91,664
 (224,384)
Income before income taxes71,607
 19,880
          
Income tax expense
 5
 
 106
5,811
 
Net income (loss)$43,848
 $(19,241) $91,664
 $(224,490)
Net income$65,796
 $19,880
          
Net income (loss) per common share:       
Net income per common share:   
Basic$0.22
 $(0.10) $0.46
 $(1.36)$0.27
 $0.10
Diluted$0.22
 $(0.10) $0.46
 $(1.36)$0.27
 $0.10
          
Weighted-average shares outstanding:          
Basic200,881,447
 200,515,555
 200,807,436
 164,771,544
241,751,915
 200,707,891
Diluted201,460,915
 200,515,555
 201,326,129
 164,771,544
243,166,897
 201,309,251

The accompanying notes are an integral part of these condensed consolidated financial statements
SRC ENERGY INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited; in thousands)

 Nine Months Ended September 30,
 2017 2016
Cash flows from operating activities:   
Net income (loss)$91,664
 $(224,490)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:   
Depletion, depreciation, and accretion73,396
 33,001
Full cost ceiling impairment
 215,223
Settlement of asset retirement obligation(4,077) (196)
Stock-based compensation8,390
 7,285
Mark-to-market of commodity derivative contracts:   
Total (gain) loss on commodity derivatives contracts(2,324) 3,617
Cash settlements on commodity derivative contracts778
 5,137
Changes in operating assets and liabilities:   
Accounts receivable   
Oil, natural gas, and NGL sales(46,581) 602
Trade(38,446) 2,679
Accounts payable and accrued expenses1,413
 1,761
Revenue payable41,997
 (363)
Production taxes payable17,548
 (10,158)
Other(941) (905)
Net cash provided by operating activities142,817
 33,193
    
Cash flows from investing activities:   
Acquisition of oil and gas properties and leaseholds(62,562) (503,357)
Capital expenditures for drilling and completion activities(305,636) (72,375)
Other capital expenditures(11,198) (3,078)
Land and other property and equipment(4,087) (3,339)
Cash held in escrow18,248
 (18,244)
Proceeds from sales of oil and gas properties and other77,017
 24,223
Net cash used in investing activities(288,218) (576,170)
    
Cash flows from financing activities:   
Proceeds from the sale of stock
 565,398
Offering costs
 (21,987)
Proceeds from the employee exercise of stock options114
 
Payment of employee payroll taxes in connection with shares withheld(631) (510)
Proceeds from the revolving credit facility170,000
 55,000
Principal repayments on the revolving credit facility(20,000) (133,000)
Financing fees on amendments to the revolving credit facility(1,372) (269)
Proceeds from issuance of the notes payable
 80,000
Financing fees on issuance of the notes payable
 (4,397)
Net cash provided by financing activities148,111
 540,235
    
Net increase (decrease) in cash and equivalents2,710
 (2,742)
    
Cash and equivalents at beginning of period18,615
 66,499
    
Cash and equivalents at end of period$21,325
 $63,757
 Three Months Ended March 31,
 2018 2017
Cash flows from operating activities:   
Net income$65,796
 $19,880
Adjustments to reconcile net income to net cash provided by operating activities:   
Depletion, depreciation, and accretion37,081
 13,229
Settlement of asset retirement obligation(2,461) (764)
Provision for deferred taxes5,811
 
Stock-based compensation expense2,796
 2,675
Mark-to-market of commodity derivative contracts:   
Total (gain) loss on commodity derivatives contracts5,781
 (3,379)
Cash settlements on commodity derivative contracts(1,555) 81
Changes in operating assets and liabilities:14,432
 (2,364)
Net cash provided by operating activities127,681
 29,358
    
Cash flows from investing activities:   
Acquisition of oil and gas properties and leaseholds(1,329) (25,082)
Capital expenditures for drilling and completion activities(100,347) (55,464)
Other capital expenditures(3,640) (2,416)
Acquisition of land and other property and equipment(317) (2,072)
Proceeds from sales of oil and gas properties and other728
 70,689
Net cash used in investing activities(104,905) (14,345)
    
Cash flows from financing activities:   
Offering costs(157) 
Proceeds from the employee exercise of stock options1,063
 
Payment of employee payroll taxes in connection with shares withheld(475) (431)
Proceeds from the revolving credit facility
 20,000
Principal repayments on the revolving credit facility
 (20,000)
Financing fees on issuance of notes payable and amendments to revolving credit facility(149) 
Capital lease payments(87) 
Net cash provided by (used in) financing activities195
 (431)
    
Net increase in cash, cash equivalents, and restricted cash22,971
 14,582
    
Cash, cash equivalents, and restricted cash at beginning of period48,772
 36,834
    
Cash, cash equivalents, and restricted cash at end of period$71,743
 $51,416
Supplemental Cash Flow Information (See Note 15)16)

The accompanying notes are an integral part of these condensed consolidated financial statements

SRC ENERGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

1.Organization and Summary of Significant Accounting Policies

Organization:  SRC Energy Inc. (the "Company," "SRC Energy," "we," "us," or "our") is an independent oil and natural gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids ("NGLs"), primarily in the Denver-Julesburg Basin ("D-J Basin") of Colorado. On June 15, 2017, our shareholders approved an amendment to the Amended and Restated Articles of Incorporation of the Company to change the name of the Company from Synergy Resources Corporation to SRC Energy Inc. The Company had been using the new name on a "doing business as" basis since March 6, 2017. In addition to using the new name, the Company’s common stock which is listed and traded on the NYSE MKT, changed toAmerican under the new symbol "SRCI."

Basis of Presentation:  The Company operates in one business segment, and all of its operations are located in the United States of America.

At the directive of the Securities and Exchange Commission ("SEC") to use "plain English" in public filings, the Company will use such terms as "we," "our," "us," or the "Company" in place of SRC Energy Inc. When such terms are used in this manner throughout this document, they are in reference only to the corporation, SRC Energy Inc., and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.

The condensed consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.  The Company prepares its condensed consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”).

Interim Financial Information:  The unaudited condensed consolidated interim financial statements included herein have been prepared by the Company pursuant to the rules and regulations of the SEC as promulgated in Rule 10-01 of Regulation S-X.  The condensed consolidated balance sheet as of December 31, 20162017 was derived from the Company's annual consolidated financial statements included within its Annual Report on Form 10-K for the year ended December 31, 20162017 as filed with the SEC on February 23, 2017.21, 2018.  Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations.  The Company believes that the disclosures included are adequate to make the information presented not misleading and recommends that these condensed financial statements be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 2016.2017.

In our opinion, the unaudited condensed consolidated financial statements contained herein reflect all adjustments, consisting solely of normal recurring items, which are necessary for the fair presentation of the Company's financial position, results of operations, and cash flows on a basis consistent with that of its prior audited financial statements.  However, the results of operations for interim periods may not be indicative of results to be expected for the full fiscal year.

Major Customers: The Company sells production to a small number of customers as is customary in the industry. Customers representing 10% or more of our oil, natural gas, and NGL revenuerevenues (“major customers”) for each of the periods presented are shown in the following table:
 Three Months Ended September 30, Nine Months Ended September 30, Three Months Ended March 31,
Major Customers 2017 2016 2017 2016 2018 2017
Company A 30% * 27% * 31% 23%
Company B 27% 20% 26% 20% 19% 22%
Company C 13% 12% 15% * 17% 31%
Company D * 10% * 11% 13% *
Company E * 27% * 38%
* less than 10%

Based on the current demand for oil and natural gas, the availability of other buyers, the multiple contracts for sales of our products, and the Company having the option to sell to other buyers if conditions warrant, the Company believes that the loss of our existing customers or individual contractcontracts would not have a material adverse effect on us. Our oil and natural gas production

is a commodity with a readily available market, and we sell our products under many distinct contracts. In addition, there are several oil and natural gas purchasers and processors within our area of operations to whom our production could be sold.
 

Accounts receivable consist primarily of receivables from oil, natural gas, and NGL sales and amounts due from other working interest owners who are liable for their proportionate share of well costs. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners.

Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table (these companies do not necessarily correspond to those presented above):
 As of As of As of As of
Major Customers September 30, 2017 December 31, 2016 March 31, 2018 December 31, 2017
Company A 25% 23% 22% 16%
Company B 16% * 21% 26%
Company C * 43% 15% 23%
Company D * 10% * 11%
* less than 10%

The Company operates exclusively within the United States of America, and except for cash and cash equivalents, all of the Company’s assets are utilized in, and all of our revenues are derived from, the oil and gas industry.

Recently Adopted Accounting Pronouncements:

In March 2016,May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting StandardsStandard Update ("ASU") 2016-09, “Improvements to Employee Share-Based Payment Accounting”2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2016-09”2014-09”), which intendsestablishes a comprehensive new revenue recognition standard designed to improvedepict the accountingtransfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for share-based payment transactions.those goods or services. In March 2016, the FASB released certain implementation guidance through ASU 2016-09 changes several aspects2016-08 (collectively with ASU 2014-09, the "Revenue ASUs") to clarify principal versus agent considerations. The Revenue ASUs allow for the use of either the accounting for share-based payment award transactions, including: (1) Accountingfull or modified retrospective transition method, and Cash Flow Classification for Excess Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 isthe standard will be effective for public businesses for fiscal years, and interimannual reporting periods within those fiscal years, beginning after December 15, 2016,2017 including interim periods within that period, with early adoption permitted. Wepermitted for annual reporting periods beginning after December 15, 2016. The Company adopted this pronouncementthe guidance using the modified retrospective method with the effective date of January 1, 2017. Upon adoption of this standard, we no longer estimate the total number of awards for which the requisite service period will2018. The Company did not be rendered, and effective January 1, 2017, we began accounting for forfeitures when they occur. We applied this accounting change on a modified retrospective basis withrecord a cumulative-effect adjustment to the opening balance of $0.1 million to retained earnings as of the date of adoption.no adjustment was necessary. The adoption of the other provisionsRevenue ASUs did not materially impact net income or cash flows. See Note 14 for the consolidated financial statements.

In January 2017,new disclosures required by the FASB issued ASU 2017-04, "Simplifying the Test for Goodwill Impairment" ("ASU 2017-04"), which removes the requirement to compare the implied fair value of goodwill with its carrying amount as part of step 2 of the goodwill impairment test. We adopted ASU 2017-04 on January 1, 2017, and it will be applied for any interim or annual goodwill impairment tests subsequent to that date. The adoption of this guidance is not expected to materially impact the consolidated financial statements.Revenue ASUs.

Recently Issued Accounting Pronouncements:   We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us. 

In November 2016, the FASB issued ASU 2016-18, "Restricted Cash" ("ASU 2016-18"), which amends ASC 230 to add or clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. Key requirements of ASU 2016-18 are as follows: 1) An entity should include in its cash and cash-equivalent balances in the statement of cash flows those amounts that are deemed to be restricted cash and restricted cash equivalents. ASU 2016-18 does not define the terms “restricted cash” and “restricted cash equivalents” but states that an entity should continue to provide appropriate disclosures about its accounting policies pertaining to restricted cash in accordance with other GAAP. ASU 2016-18 also states that any change in accounting policy will need to be assessed under ASC 250; 2) A reconciliation between the statement of financial position and the statement of cash flows must be disclosed when the statement of financial position includes more than one line item for cash, cash equivalents, restricted cash, and restricted cash equivalents; 3) Changes in restricted cash and restricted cash equivalents that result from transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows; and 4) An entity with a material balance of amounts generally described as restricted cash and restricted cash equivalents must disclose information about the nature of the restrictions. The guidance is effective for fiscal years beginning after December 15, 2017, including interim periods therein. Early adoption is permitted, and we must apply

the guidance retrospectively to all periods presented. We are currently evaluating the impact of the adoption of this standard on our condensed consolidated financial statements.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" ("ASU 2016-02"), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous US GAAP. ASU 2016-02 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted.2018. We are currently evaluating the impact of the adoption of this standard on our condensed consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 (collectively with ASU 2014-09, the "Revenue ASUs") to clarify principal versus agent considerations. The Revenue ASUs allow for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2017 including interim periods within that period, with early adoption permitted for annual reporting periods beginning after December 15, 2016. While the Company does not expect net income (loss) or cash flows to be impacted, the Company is currently analyzing whether changes to total revenues and total expenses will be necessary to properly reflect revenue for certain pipeline gathering, transportation, and gas processing agreements. The Company continues to evaluate the expected disclosure requirements, changes to relevant business practices, accounting policies, and control activities that will occur as a result of the adoption of this ASU. The Company plans to adopt the guidance using the modified retrospective method on the effective date of January 1, 2018.

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.

Change in estimates: During the ninethree months ended September 30,March 31, 2017, the Company adjusted its estimate for production taxes based on recent historical experience and additional information received during the period.periods. During the ninethree months ended September 30,March 31, 2017, the Company decreased the accrual for production taxes to be paid by approximately $1.1 million, which$2.0 million. This increased our operating income by a corresponding amount, or $0.01 per basic and diluted common share. During the three months ended September 30, 2016, the Company reduced its estimate for ad valorem taxes based on additional information received during that period. As a result, the Company decreased taxes to be paid by approximately $3.6 million which reduced our operating loss for the three and nine months ended September 30, 2016 by a corresponding amount, or $0.02 per basic and diluted common share.


2.Property and Equipment

The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
As of As ofAs of As of
September 30, 2017 December 31, 2016March 31, 2018 December 31, 2017
Oil and gas properties, full cost method:      
Costs of proved properties:   
Producing and non-producing$1,717,432
 $1,629,789
Less, accumulated depletion and full cost ceiling impairments(695,707) (659,205)
Subtotal, proved properties, net1,021,725
 970,584
   
Costs of wells in progress149,214
 106,269
   
Costs of unproved properties and land, not subject to depletion:      
Lease acquisition and other costs$319,954
 $392,561
788,798
 786,469
Land7,200
 5,986
7,427
 7,200
Subtotal, unproved properties and land327,154
 398,547
796,225
 793,669
   
Costs of wells in progress158,192
 81,780
   
Costs of proved properties:   
Producing and non-producing1,375,937
 969,239
Less, accumulated depletion and full cost ceiling impairments(617,802) (545,157)
Subtotal, proved properties, net758,135
 424,082
      
Costs of other property and equipment:      
Other property and equipment7,790
 5,063
8,484
 8,134
Less, accumulated depreciation(1,638) (736)(2,539) (2,080)
Subtotal, other property and equipment, net6,152
 4,327
5,945
 6,054
      
Total property and equipment, net$1,249,633
 $908,736
$1,973,109
 $1,876,576

The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value. For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. At September 30,March 31, 2018 and 2017, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary. At September 30, 2016, the carrying value of our oil and gas properties subject to the test exceeded the calculated value of the ceiling limitation, resulting in an impairment of $25.5 million for the three months ended September 30, 2016. Impairments for the nine months ended September 30, 2016 totaled $215.2 million. No impairments were recognized for the comparable 2017 periods.necessary.

Capitalized Overhead: A portion of the Company’s overhead expenditures are directly attributable to acquisition, exploration, and development activities.  Under the full cost method of accounting, these expenditures, in the amounts shown in the table below, were capitalized in the full cost pool (in thousands):
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Capitalized overhead$2,518
 $1,757
 $7,729
 $4,745
 Three Months Ended March 31,
 2018 2017
Capitalized overhead$3,113
 $2,680

3.Acquisitions, Swaps, and Divestitures
3.    Acquisitions, Swaps, and Divestitures

Acquisitions and Swaps

December 2017 Acquisition

In December 2017, the Company completed the purchase of a total of approximately 30,200 net acres and the associated non-operated production in the Greeley-Crescent development area in Weld County Colorado, primarily south of the city of Greeley, for $577.5 million, comprised of $576.3 million in cash and the assumption of certain liabilities ("GCII Acquisition"). The Company seekspurchase price has preliminarily been allocated as $60.8 million to acquire developed and undevelopedproved oil and gas properties and $516.7 million to unproved oil and gas properties, pending the final closing. The effective date of this part of the transaction was November 1, 2017. The agreement also contemplates a second closing at which we will acquire operated producing properties subject to certain regulatory restrictions. The purchase price payable at the second closing will be determined based on the amount of then-current production from the properties conveyed and is expected to be completed in the core Wattenberg Field to provide additional mineral acres uponsecond half of 2018. For the second closing, the effective date will be the first day of the calendar month in which the Company can drill wellsclosing for such properties occurs. The second closing is subject to

certain closing conditions including the receipt of regulatory approval. Accordingly, the second closing of the transaction may not occur in the expected time frame or at all.

The first closing was accounted for as an asset acquisition under ASC 805, Business Combinations, which requires the acquired assets and produce hydrocarbons.liabilities to be recorded at cost on the acquisition date of December 15, 2017.

September 2017 Acquisition

In September 2017, we completed the second closing contemplated by the May 2016 purchase and sale agreement pursuant to which we agreed to acquire a total of approximately 33,100 net acres in the GC Acquisition (as defined in "-June 2016Greeley-Crescent area for $505 million (the "GC Acquisition" below)). AtThe assets acquired at the second closing we acquiredwere comprised of 335 operated vertical wells and 7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the horizontal wells acquired and September 1, 2017 for the vertical wells acquired. At the second closing, the escrow balance of $18.2 million was released and $11.4 million of that amount was returned to the Company.

The total purchase price for the assets acquired at the second closing was $31.3$30.3 million, composed of cash of $6.8$6.3 million and assumed liabilities of $24.5$24.0 million. The assumed liabilities included $20.9 million for asset retirement obligations. The entire purchase price has been allocated to proved oil and gas properties.

August 2017 Acquisition and Swap

In August 2017, we entered into an agreement with another party to trade approximately 3,200 net acres of the Company's non-contiguous acreage for approximately 3,200 net acres within the Company's core operating area. This transaction closed in the fourth quarter of 2017. Also in August 2017, we acquired approximately 1,000 net acres of developed and undeveloped leasehold and mineral interests, along with the associated production, for a total purchase price of $22.6 million, composed of cash and assumed liabilities.

In August 2017, we also entered into an agreement with another party The purchase price for the acquisition has preliminarily been allocated as $6.7 million to trade approximately 4,000 net acres ofproved oil and gas properties and $15.9 million to unproved oil and gas properties, pending the Company's non-contiguous acreage for approximately 4,000 net acres within the Company's core operating area. This transaction is expected to close in the fourth quarter of 2017.final closing.

March 2017 Acquisition

In March 2017, we closed an acquisition comprised primarily of developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.0$25.1 million, composed of cash and assumed liabilities.

Acquisitions in the Second Half of 2016

In August and October 2016, the Company completed four acquisitions of certain assets for a total purchase price of $13.5 million, composed of cash, forgiven receivables, and assumed liabilities. The acquired properties were comprised primarily of undeveloped oil and gas leasehold interests and additional interests in developed properties operated by the Company.

June 2016 Acquisition

In May 2016, we entered into a purchase and sale agreement (the "GC Agreement") pursuant to which we agreed to acquire a total of approximately 72,000 gross (33,100 net) acres in an area referred to as the Greeley-Crescent project in the Wattenberg Field for $505 million (the "GC Acquisition").

In June 2016, the Company closed on the portion of the assets comprised of undeveloped oil and gas leasehold interests and non-operated production. The effective date of this part of the transaction was April 1, 2016. As discussed above in "- September 2017 Acquisition" above,we closed on the second part of this transaction covering the operated producing properties in September 2017.

The first closing on June 14, 2016 was for a total purchase price of $486.4 million, net of customary closing adjustments. The purchase price was composed of $485.1 million in cash plus the assumption of certain liabilities. The first closing encompassed approximately 33,100 net acres of oil and gas leasehold interests and related assets and net production of approximately 800 BOED at the time of entering into the GC Agreement.

The first closing was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of June 14, 2016. Transaction costs of $0.5 million related to the acquisition were expensed as incurred. The following table summarizes the purchase price and final fair values of assets acquired and liabilities assumed (in thousands):
Purchase PriceJune 14, 2016
Consideration given: 
Cash$485,141
Net liabilities assumed, including asset retirement obligations1,273
Total consideration given$486,414
  
Allocation of Purchase Price 
Proved oil and gas properties (1)
$132,903
Unproved oil and gas properties353,511
Total fair value of assets acquired$486,414
(1) Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement.

The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of11.5%, and assumptions regarding the timing and amount of future development and operating costs.

For thethree and nine months endedSeptember 30, 2017, the results of operations of the acquired assets, representing approximately$1.4 millionand$5.5 million of revenue, respectively, and $0.9 million and $5.0 million of operating income, respectively, have been included in the Company's condensed consolidated statements of operations.

The following table presents the unaudited pro forma combined results of operations for the three and nine months ended September 30, 2016 as if the first closing had occurred on January 1, 2015.  The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired.  The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired.  The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.
(in thousands)Three Months Ended September 30, 2016 Nine Months Ended September 30, 2016
Oil, natural gas, and NGL revenues$26,234
 $71,940
Net loss$(19,241) $(227,479)
    
Net loss per common share   
Basic$(0.10) $(1.14)
Diluted$(0.10) $(1.14)

February 2016 Acquisition

On February 4, 2016, the Company completed the acquisition of undeveloped oil and gas leasehold interests for a total purchase price of $10.0 million. The purchase price has been allocated as $8.6$15.3 million to proved oil and gas properties, and $1.4$9.4 million to unproved oil and gas properties. See Note 9 for further details asproperties, and $0.4 million to the preparation of these significant estimates.other assets and land.

Divestitures

In October 2017, we executed a purchase and sale agreement with a private party resulting in the divestiture of approximately 1,100 net acres and 22 gross (4 net) non-operated wells in progress for $11.6 million. The transaction is expected to close in the fourth quarter of 2017. Additionally, we completed an additional divestiture to a separate private party of 37 operated vertical wells for total consideration of approximately $0.7 million in cash and the assumption by the buyers of $2.3 million in liabilities.

During the nine monthsyear ended September 30,December 31, 2017, we completed divestitures of approximately 10,70016,000 net undeveloped acres, along with associated production, outside of the Company's core development area for approximately $75.1$91.6 million in cash and the assumption by the buyers of $1.7$5.2 million in asset retirement obligations and $0.6$22.2 million in other liabilities. In accordance with full cost accounting guidelines, the net proceeds were credited to the full cost pool.

In April 2016, the Company agreed to divest approximately 3,700 net undeveloped acres and 107 vertical wells, along with the associated production, primarily in Adams County, Colorado for total consideration of approximately $24.7 million in cash and the assumption by the buyers of $0.5 million in liabilities and $3.6 million in asset retirement obligations. The vertical well transaction closed in April 2016, and the undeveloped acreage transaction closed in June 2016. In accordance with full cost accounting guidelines, the net proceeds were credited to the full cost pool.


4.Depletion, depreciation, and accretion ("DD&A")

DD&A consisted of the following (in thousands):
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended March 31,
2017 2016 2017 20162018 2017
Depletion of oil and gas properties$32,944
 $9,273
 $71,389
 $31,981
$36,102
 $12,703
Depreciation and accretion796
 362
 2,007
 1,020
979
 526
Total DD&A Expense$33,740
 $9,635
 $73,396
 $33,001
$37,081
 $13,229

Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter. For the three and nine months ended September 30, 2017,March 31, 2018, production of 3,7154,086 MBOE and 8,280 MBOE, respectively, represented 2.2% and 4.8%1.7% of estimated total proved reserves, respectively.reserves. For the three and nine months ended September 30, 2016,March 31, 2017, production of 9931,597 MBOE and 3,050 MBOE, respectively, represented 0.8% and 2.4%1.1% of estimated total proved reserves, respectively.reserves. DD&A expense was $9.08 per BOE and $9.70$8.28 per BOE for the three months ended September 30,March 31, 2018 and 2017, and 2016, respectively, and was $8.86 per BOE and $10.82 per BOE for the nine months ended September 30, 2017 and 2016, respectively.


5.Asset Retirement Obligations

Upon completion or acquisition of a well, the Company recognizes obligations for its oil and natural gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling site to its original use.  The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in regulations.  Changes in estimates are reflected in the obligations as they occur.  If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the capitalized asset retirement cost.  The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands):
Nine Months Ended September 30, 2017Three Months Ended March 31, 2018
Asset retirement obligations, December 31, 2016$16,458
Asset retirement obligations, December 31, 2017$31,622
Obligations incurred with development activities2,782
223
Obligations assumed with acquisitions23,521
5
Accretion expense981
520
Obligations discharged with asset retirements and divestitures(7,023)(2,860)
Asset retirement obligation, September 30, 2017$36,719
Asset retirement obligation, March 31, 2018$29,510
Less, current portion(2,738)(4,180)
Long-term portion$33,981
$25,330

6.Revolving Credit Facility

The Company maintains a revolving credit facility (sometimes referred to as the "Revolver") with a bank syndicate with a maturity date of December 15, 2019.April 2, 2023. The Revolver is available for working capital requirements, capital expenditures,for exploration and production operations, acquisitions of oil and gas properties, general corporate purposes, and to support letters of credit. As of September 30, 2017,AtMarch 31, 2018, the terms of the Revolver provideprovided for up to $500$500 millionin borrowings, subject to a borrowing base limitation of $400$400 million. ThereAs of March 31, 2018 and December 31, 2017, there was a $150.0 million nooutstanding principal balance as of September 30, 2017 and no outstanding principal balance as of Decemberbalance. AtMarch 31, 2016. The2018, the Company hashad an outstanding letter of credit of approximately $0.5$0.5 million.

In September 2017,On April 2, 2018, the lendersCompany entered into a second amended and restated credit agreement (the “Restated Credit Agreement”) with certain banks and other lenders. The Restated Credit Agreement provides for a maximum credit amount of $1.5 billion, an aggregate elected commitment of $450 million, and a borrowing base of $550 million. The Company is currently allowed to borrow up to $450 million under the Revolver completed their regular semi-annual redeterminationRestated Credit Agreement, less any outstanding amounts. In addition, the Restated Credit Agreement extends the maturity date of our borrowing base.  The borrowing base was increasedthe facility from $225December 2019 to April 2023, reflects certain reductions in interest rates applicable to borrowings under the facility, and adds a $25 million to $400 million.swingline facility. The next semi-annual redetermination is scheduled for AprilNovember 2018.

Interest under the Revolver accrues monthly at a variable rate.  For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or the London Interbank Offered Rate ("LIBOR")LIBOR plus a margin. The interest rate margin, as well as other bank fees, varies with utilization of the Revolver. The average annual interest rate for borrowings during the ninethree months ended September 30,March 31, 2017 and 2016 was 3.3% and 2.6%2.8%, respectively..

Certain of the Company’s assets, including substantially all of theits producing wells and developed oil and gas leases, have been designated as collateral under the Revolver.Restated Credit Agreement. The borrowing commitmentamount available to be borrowed is subject to scheduled redeterminations on a semi-annual basis. If certain events occur or if the bank syndicate or the Company so elects in certain circumstances, an unscheduled redetermination could be undertaken.

The RevolverRestated Credit Agreement contains covenants that, among other things, restrict the payment of dividends and limit our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of estimated proved developed producing or total proved reserves as projected in the semi-annual reserve report.
  
Furthermore, the RevolverRestated Credit Agreement requires the Company to maintain compliance with certain financial and liquidity ratio covenants. In particular, the Company must not (a) permit its ratio of total funded debt to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0 as of the endlast day of any fiscal quarter; or (b) as of the last day of any fiscal quarter permit its ratio of current ratio,assets to current liabilities, each as defined in the agreement, to be less than 1.0 to 1.0.1.0as of the last day of any fiscal quarter. As

of September 30, 2017,March 31, 2018, the most recent compliance date, the Company was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.

7.Notes Payable

2025 Senior Notes

In June 2016,November 2017, the Company issued $80$550 million aggregate principal amount of 9%6.25% Senior Notes ("(the "2025 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021.December 1, 2025. Interest on the 2025 Senior Notes accrues at 9%6.25% and began accruing on June 14, 2016.November 29, 2017. Interest is payable on June 151 and December 151 of each year.year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 (the "Indenture")November 29, 2017 and will beare guaranteed on a senior unsecured basis by anythe Company’s existing and future subsidiaries of the Company that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility.Revolver. The net proceeds from the sale of the 2025 Senior Notes were $75.2$538.1 million after deductions of $4.8$11.9 million for expenses and underwriting discounts and commissions. The associated expenses and underwriting discounts and commissions are amortized using the interest method at an effective interest rate of 10.6% 6.6%. The net proceeds were used to fund the GCGCII Acquisition as discussed further in Note 3. 3, to repay the 2021 Senior Notes, and to pay off the outstanding Revolver balance.

At any time prior to December 14, 2018,1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to 100% of the Make-Whole Priceprincipal amount plus an Applicable Premium (as defined in the Indenture) and accrued and unpaidunpaid interest.  On and after December 14, 2018,1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to a specified percentage of the principal amount of the redeemed notes (104.50% (104.688% for 2018, 102.25%2020, 103.125% for 2019,2021, 101.563%for 2022, and 100% for 20202023 and thereafter, during the twelve-month period beginning on December 141 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018,1, 2020, the Company can, on one or more occasions, redeem up to35%of the principal amount of the 2025 Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to 109%106.25% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.

The Indenture contains covenants that restrict the Company’s ability and the ability of any restrictedcertain of its subsidiaries to, among other things:restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities.  These covenants are subject to a number of exceptions and qualifications.

As of September 30, 2017,March 31, 2018, the most recent compliance date, the Company was in compliance with these covenants and expects to remain in compliance throughout the next 12-month period.

8.Commodity Derivative Instruments

The Company has entered into commodity derivative instruments as described below. Our commodity derivative instruments may include but are not limited to "collars," "swaps," and "put" positions. Our derivative strategy, including the volumes and commodities covered and the relevant strike prices, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in the Revolver.

A "put" option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may at times purchase put options, which require us to pay premiums at the time we purchase the contracts. These premiums represent the fair value of the purchased put as of the date of purchase.


A "call" option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, sell call options in conjunction with the purchase of put options to create "collars." We regularly utilize "no premium" (a.k.a. zero cost) collars where the cost of the put is offset by the proceeds of the call. At settlement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling price and the index price if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling price.

Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price over a specified term.

The Company may, from time to time, add incremental derivatives to cover additional production, restructure existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with five counterparties and an exchange. Three of the counterparties are lenders in the Revolver. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying condensed consolidated balance sheets as commodity derivative assets or liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from contract settlement of derivatives are recorded in the condensed consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements

under commodity derivative contracts result in it making or receiving a payment to or from the counterparty. Actual cash settlements can occur at either the scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s condensed consolidated statements of cash flows.


The Company’s commodity derivative contracts as of September 30, 2017March 31, 2018 are summarized below:
Settlement Period 
Derivative
Instrument
 
Average Volumes
(Bbls
per month)
 
Floor
Price
 
Ceiling
Price
Crude Oil - NYMEX WTI        
Oct 1, 2017 - Dec 31, 2017 Collar 30,667
 $40.00
 $60.00
Oct 1, 2017 - Dec 31, 2017 Collar 20,000
 $45.00
 $70.00
Oct 1, 2017 - Dec 31, 2017 Collar 30,667
 $40.00
 $65.00
Oct 1, 2017 - Dec 31, 2017 Collar 30,667
 $40.00
 $65.00
Oct 1, 2017 - Dec 31, 2017 Collar 15,333
 $45.00
 $65.00
Oct 1, 2017 - Dec 31, 2017 Collar 15,333
 $45.00
 $65.10
Jan 1, 2018 - Dec 31, 2018 Collar 76,042
 $40.00
 $57.60
         
Settlement Period 
Derivative
Instrument
 
Average Volumes
(MMBtu
per month)
 
Floor
Price
 
Ceiling
Price
Natural Gas - NYMEX Henry Hub        
Oct 1, 2017 - Dec 31, 2017 Collar 100,000
 $2.75
 $4.00
Oct 1, 2017 - Dec 31, 2017 Collar 153,333
 $2.75
 $3.90
Oct 1, 2017 - Dec 31, 2017 Collar 92,000
 $2.75
 $4.10
Oct 1, 2017 - Dec 31, 2017 Collar 15,333
 $3.00
 $4.31
Oct 1, 2017 - Dec 31, 2017 Collar 110,400
 $3.00
 $4.30
Oct 1, 2017 - Dec 31, 2017 Collar 199,333
 $3.00
 $3.88
Oct 1, 2017 - Dec 31, 2017 Collar 199,333
 $3.00
 $3.91
         
Natural Gas - CIG Rocky Mountain        
Oct 1, 2017 - Dec 31, 2017 Collar 200,000
 $2.50
 $3.27
Oct 1, 2017 - Dec 31, 2017 Collar 100,000
 $2.60
 $3.20
Jan 1, 2018 - Dec 31, 2018 Collar 456,250
 $2.25
 $2.81

Subsequent to September 30, 2017, the Company added the following positions:
Settlement Period 
Derivative
Instrument
 
Volumes
(Bbls per day)
 
Weighted-Average
Floor Price
 Weighted-Average Ceiling Price
Crude Oil - NYMEX WTI        
Apr 1, 2018 - Dec 31, 2018 Collar 10,000
 $43.63
 $61.29
         
Settlement Period 
Derivative
Instrument
 
Volumes
(MMBtu per day)
 Weighted-Average
Floor Price
 Weighted-Average Ceiling Price
Natural Gas - CIG Rocky Mountain        
Apr 1, 2018 - Dec 31, 2018 Collar 15,000
 $2.25
 $2.82
Settlement Period 
Derivative
Instrument
 Average Volumes
(Bbls
per month)
 
Floor
Price
 
Ceiling
Price
Crude Oil - NYMEX WTI        
Jan 1, 2018 - Dec 31, 2018 Collar 76,042
 $45.00
 $58.00
Settlement Period 
Derivative
Instrument
 Volumes
(Bbls per day)
 Fixed Price
Propane - Mont Belvieu      
Apr 1, 2018 - Dec 31, 2018 Swap 1,000
 $33.60

Offsetting of Derivative Assets and Liabilities

As of September 30, 2017March 31, 2018 and December 31, 2016,2017, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of either party, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that, in the event of an early termination, each party has the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its condensed consolidated balance sheets.

The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying condensed consolidated balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands):
 As of September 30, 2017 As of March 31, 2018
Underlying 
Balance Sheet
Location
 Gross Amounts of Recognized Assets and Liabilities 
Gross Amounts Offset in the
Balance Sheet
 
Net Amounts of Assets and Liabilities Presented in the
Balance Sheet
 
Balance Sheet
Location
 Gross Amounts of Recognized Assets and Liabilities 
Gross Amounts Offset in the
Balance Sheet
 
Net Amounts of Assets and Liabilities Presented in the
Balance Sheet
Commodity derivative contracts Current assets $1,214
 $(1,214) $
 Current assets $1,828
 $(1,828) $
Commodity derivative contracts Noncurrent assets $502
 $(502) $
 Noncurrent assets $
 $
 $
Commodity derivative contracts Current liabilities $2,000
 $(1,214) $786
 Current liabilities $13,402
 $(1,828) $11,574
Commodity derivative contracts Noncurrent liabilities $896
 $(502) $394
 Noncurrent liabilities $
 $
 $
 As of December 31, 2016 As of December 31, 2017
Underlying 
Balance Sheet
Location
 Gross Amounts of Recognized Assets and Liabilities 
Gross Amounts Offset in the
Balance Sheet
 
Net Amounts of Assets and Liabilities Presented in the
Balance Sheet
 
Balance Sheet
Location
 Gross Amounts of Recognized Assets and Liabilities 
Gross Amounts Offset in the
Balance Sheet
 
Net Amounts of Assets and Liabilities Presented in the
Balance Sheet
Commodity derivative contracts Current assets $2,045
 $(1,748) $297
 Current assets $1,960
 $(1,960) $
Commodity derivative contracts Noncurrent assets $
 $
 $
 Noncurrent assets $
 $
 $
Commodity derivative contracts Current liabilities $4,622
 $(1,748) $2,874
 Current liabilities $9,825
 $(1,960) $7,865
Commodity derivative contracts Noncurrent liabilities $
 $
 $
 Noncurrent liabilities $
 $
 $

The amount of gain (loss) recognized in the condensed consolidated statements of operations related to derivative financial instruments was as follows (in thousands):
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended March 31,
2017 2016 2017 20162018 2017
Realized gain (loss) on commodity derivatives$116
 $(13) $(26) $2,868
Realized loss on commodity derivatives$(2,072) $(119)
Unrealized gain (loss) on commodity derivatives(2,499) 420
 2,350
 (6,485)(3,709) 3,498
Total gain (loss)$(2,383) $407
 $2,324
 $(3,617)$(5,781) $3,379

Realized gains and losses include cash received from the monthly settlement of derivative contracts at their scheduled maturity date andnet of the previously incurred premiums attributable to settled commodity contracts. The following table summarizes derivative realized gains and losses during the periods presented (in thousands):
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended March 31,
2017 2016 2017 20162018 2017
Monthly settlement$376
 $497
 $927
 $4,398
$(2,072) $225
Previously incurred premiums attributable to settled commodity contracts(260) (510) (953) (1,530)
 (344)
Total realized gain (loss)$116
 $(13) $(26) $2,868
Total realized loss$(2,072) $(119)

Credit Related Contingent Features

As of September 30, 2017,March 31, 2018, three of the six counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the credit facility and its derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with the fourth counterparty,and fifth counterparties, which isare not a lenderlenders under the credit facility, is unsecured and does not require the posting of collateral. The agreement with the fifthsixth counterparty, which is not a lender under the credit facility, may require the posting of collateral if in a liability position. The agreement with the sixth counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility.

9.Fair Value Measurements

ASC 820, Fair Value Measurements and Disclosure, establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.  Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company.  Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances.  The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1: Quoted prices available in active markets for identical assets or liabilities;
Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; and
Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow or other valuation models.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The Company’s non-recurring fair value measurements include unproved properties, asset retirement obligations, and purchase price allocations for the fair value of assets and liabilities acquired through business combinations and certain asset acquisitions. Please refer to Notes 2, 3, and 5 for further discussion of unproved properties, business combinations and asset acquisitions, and asset retirement obligations, respectively.

The Company determines the estimated fair value of its unproved properties using market comparables, which are deemed to be a Level 3 input. See Note 2 for additional information.

The acquisition of a group of assets in a business combination transaction and certain asset acquisitions requires fair value estimates for assets acquired and liabilities assumed.  The fair value of assets and liabilities acquired is calculated using a net discounted cash flow approach for the proved producing, proved undeveloped, probable, and possible properties. The discounted cash flows are developed using the income approach and are based on management’s expectations for the future.  Unobservable inputs include estimates of future

oil and natural gas production from the Company’s reserve reports, commodity prices based on the NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). For unproved properties, the fair value is determined using market comparables.

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free rate, inflation rates, and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period, and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. See Notes 3 and 5 for additional information.


The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2017 and December 31, 2016 by level within the fair value hierarchy (in thousands):
Fair Value Measurements at September 30, 2017Fair Value Measurements at March 31, 2018
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Financial assets and liabilities:              
Commodity derivative asset$
 $
 $
 $
$
 $
 $
 $
Commodity derivative liability$
 $1,180
 $
 $1,180
$
 $11,574
 $
 $11,574
Fair Value Measurements at December 31, 2016Fair Value Measurements at December 31, 2017
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Financial assets and liabilities:              
Commodity derivative asset$
 $297
 $
 $297
$
 $
 $
 $
Commodity derivative liability$
 $2,874
 $
 $2,874
$
 $7,865
 $
 $7,865

Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At September 30, 2017,March 31, 2018, derivative instruments utilized by the Company consist of putsswaps and collars. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors including public indices, the instruments themselves are traded with third-party counterparties. As such, the Company has classified these instruments as Level 2.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above), notes payable, and credit facility borrowings. The carrying values of cash and cash equivalents, cash held in escrow, accounts receivable, and accounts payable are representative of their fair values due to their short-term maturities. Due to the variable interest rate paid on the credit facility borrowings, the carrying value is representative of its fair value.

The fair value of the Senior Notesnotes payable is estimated to be $84.8$509.9 million at September 30, 2017.March 31, 2018. The Company determined the fair value of its notes payable at September 30, 2017March 31, 2018 by using observable market based information for debt instruments of similar amounts and duration. The Company has classified the notes payable as Level 2.


10.Interest Expense

The components of interest expense are (in thousands):
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Revolving bank credit facility$1,016
 $
 $1,286
 $154
Notes payable1,800
 1,800
 5,400
 2,120
Amortization of issuance costs1,090
 467
 2,267
 1,076
Less, interest capitalized(3,906) (2,267) (8,953) (3,350)
Interest expense, net of amounts capitalized$
 $
 $
 $


11.Weighted-Average Shares Outstanding

The following table sets forth the Company's outstanding equity grants which have a dilutive effect on earnings per share:
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Weighted-average shares outstanding - basic200,881,447
 200,515,555
 200,807,436
 164,771,544
Potentially dilutive common shares from:       
Stock options415,524
 
 412,902
 
Restricted stock units and stock bonus shares163,944
 
 105,791
 
Weighted-average shares outstanding - diluted201,460,915
 200,515,555
 201,326,129
 164,771,544

The following potentially dilutive securities outstanding for the periods presented were not included in the respective weighted-average shares outstanding-diluted calculation above as such securities had an anti-dilutive effect on earnings per share:
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Potentially dilutive common shares from:       
Stock options4,726,500
 5,903,500
 4,756,500
 5,903,500
Performance-vested stock units 1
951,884
 478,510
 951,884
 478,510
Restricted stock units and stock bonus shares308,094
 1,003,879
 497,806
 1,003,879
Total5,986,478
 7,385,889
 6,206,190
 7,385,889
1 The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.
 Three Months Ended March 31,
 2018 2017
Revolving bank credit facility$
 $43
Notes payable8,594
 1,800
Amortization of issuance costs and other887
 500
Less: interest capitalized(9,481) (2,343)
Interest expense, net of amounts capitalized$
 $

12.11.Stock-Based Compensation

In addition to cash compensation, the Company may compensate employees and directors with equity-based compensation in the form of stock options, performance-vested stock units, restricted stock units, stock bonus shares, warrants, and other equity awards. The Company records its equity compensation by pro-rating the estimated grant dategrant-date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the "vesting phase"period").  The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock.  Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo Model. For the periods presented, all stock-based compensation was either classified as a component within general and administrative expense in the Company's condensed consolidated statements of operations or, for that portion which is directly attributable to individuals performing acquisition, exploration, and development activities, was capitalized to the full cost pool. As of September 30, 2017,March 31, 2018, there were 4,500,000 common shares authorized for grant under the 2015 Equity Incentive Plan, of which 86,4646,217,650 shares were available for future grants.had been granted. The shares available for future grant exclude 951,884granted include 1,555,263 shares which have been reserved for future vesting of performance-vested stock units under the assumption that these awards met the criterion to vest at their maximum multiplier. At the Company's annual meeting of shareholders on May 18, 2018, the Company will request approval to increase the common shares authorized for grant under the 2015 Equity Incentive Plan to 10,500,000. In the event that this approval is not received, the grants exceeding the presently approved limit will be settled with cash.

The amount of stock-based compensation was as follows (in thousands):
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended March 31,
2017 2016 2017 20162018 2017
Stock options$1,277
 $1,274
 $3,825
 $4,107
$1,203
 $1,246
Performance-vested stock units807
 354
 2,130
 692
856
 525
Restricted stock units and stock bonus shares1,386
 1,023
 3,779
 3,341
1,336
 1,346
Total stock-based compensation$3,470
 $2,651
 $9,734
 $8,140
$3,395
 $3,117
Less: stock-based compensation capitalized(440) (278) (1,344) (856)(599) (442)
Total stock-based compensation expensed$3,030
 $2,373
 $8,390
 $7,284
$2,796
 $2,675


Stock options

No stock options were granted during the three and nine months ended September 30,March 31, 2018 or 2017. During the periods presented, the Company granted the following stock options:
 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2016
Number of options to purchase common shares350,000
 944,500
Weighted-average exercise price$6.55
 $7.20
Term (in years)10 years
 10 years
Vesting Period (in years)5 years
 3 - 5 years
Fair Value (in thousands)$1,253
 $3,381

The assumptions used in valuing stock options granted during each of the periods presented were as follows:
Nine Months Ended September 30, 2016
Expected term6.4 years
Expected volatility55%
Risk free rate1.25 - 1.75%
Expected dividend yield%

The following table summarizes activity for stock options for the periods presented:
Number of Shares Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life Aggregate Intrinsic Value (thousands)Number of Shares Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life Aggregate Intrinsic Value (thousands)
Outstanding, December 31, 20166,001,500
 $9.27
 8.0 years $6,515
Outstanding, December 31, 20175,636,834
 $9.38
 7.0 years $4,806
Granted
 
  
 
  
Exercised(30,000) 3.79
 140
(277,600) 4.07
 1,490
Expired(41,000) 11.98
  (23,400) 11.27
  
Forfeited(104,000) 11.60
  (30,000) 11.57
  
Outstanding, September 30, 20175,826,500
 $9.23
 7.2 years $8,076
Outstanding, Exercisable at September 30, 20173,146,361
 $8.77
 6.6 years $5,660
Outstanding, March 31, 20185,305,834
 $9.64
 7.0 years $5,158
Outstanding, Exercisable at March 31, 20183,076,213
 $9.48
 6.6 years $3,443

The following table summarizes information about issued and outstanding stock options as of September 30, 2017:March 31, 2018:
 Outstanding Options Exercisable Options Outstanding Options Exercisable Options
Range of Exercise Prices Options Weighted-Average Exercise Price per Share Weighted-Average Remaining Contractual Life Options Weighted-Average Exercise Price per Share Weighted-Average Remaining Contractual Life Options Weighted-Average Exercise Price per Share Weighted-Average Remaining Contractual Life Options Weighted-Average Exercise Price per Share Weighted-Average Remaining Contractual Life
Under $5.00 600,000
 $3.49
 3.9 years 574,000
 $3.46
 3.8 years 195,000
 $2.97
 3.8 years 195,000
 $2.97
 3.8 years
$5.00 - $6.99 1,012,000
 6.38
 7.2 years 549,000
 6.45
 6.0 years 1,005,000
 6.38
 6.7 years 601,400
 6.40
 5.6 years
$7.00 - $10.99 1,592,500
 9.34
 7.7 years 658,661
 9.50
 7.3 years 1,533,834
 9.36
 7.2 years 789,413
 9.43
 6.9 years
$11.00 - $13.46 2,622,000
 11.58
 7.7 years 1,364,700
 11.58
 7.6 years 2,572,000
 11.58
 7.2 years 1,490,400
 11.60
 7.1 years
Total 5,826,500
 $9.23
 7.2 years 3,146,361
 $8.77
 6.6 years 5,305,834
 $9.64
 7.0 years 3,076,213
 $9.48
 6.6 years

The estimated unrecognized compensation cost from stock options not vested as of September 30, 2017,March 31, 2018, which will be recognized ratably over the remaining vesting phase, is as follows:
Unrecognized compensation cost (in thousands)$11,101
$8,308
Remaining vesting phase2.5 years
2.1 years

Restricted stock units and stock bonus awards

The Company grants restricted stock units and stock bonus awards to directors, eligible employees, and officers as a part of its equity incentive plan.  Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each restricted stock unit or stock bonus award represents one share of the Company’s common stock to be released from restrictions upon completion of the vesting period. The awards typically vest in equal increments over three to five years. Restricted stock units and stock bonus awards are valued at the closing price of the Company’s common stock on the grant date and are recognized over the vesting period of the award.


The following table summarizes activity for restricted stock units and stock bonus awards for the ninethree months ended September 30, 2017:March 31, 2018:
Number of Shares Weighted-Average Grant-Date Fair ValueNumber of Shares Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2016890,336
 $9.54
Not vested, December 31, 20171,087,386
 $8.89
Granted669,323
 8.27
639,752
 9.12
Vested(336,445) 9.17
(276,973) 8.17
Forfeited(24,807) 9.85
(30,302) 10.16
Not vested, September 30, 20171,198,407
 $8.93
Not vested, March 31, 20181,419,863
 $9.11

The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of September 30, 2017,March 31, 2018, which will be recognized ratably over the remaining vesting phase, is as follows:
Unrecognized compensation cost (in thousands)$8,232
$11,304
Remaining vesting phase2.3 years
2.4 years

Performance-vested stock units

The Company grants two types of performance-vested stock units ("PSUs") to certain executives under its long-term incentive plan. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. The shares issued for PSUs are determined based on the Company’s performance over a three-year measurement period and vest in their entirety at the end of the measurement period. The PSUs will be settled in shares of the Company’s common stock following the end of the three-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited.

Total Shareholder Return ("TSR") PSUs - The vesting criterion for the TSR PSUs is based on a comparison of the Company’s total shareholder return ("TSR")TSR for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. As the vesting criterion is linked to the Company's share price, it is considered a market condition for purposes of calculating the grant-date fair value of the awards.

The fair value of the TSR PSUs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s TSR PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the TSR PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period, as well asand the volatilities for each of the Company’s peers.


The assumptions used in valuing the TSR PSUs granted were as follows:
Nine Months Ended September 30,Three Months Ended March 31,
2017 20162018 2017
Weighted-average expected term2.9 years
 2.7 years
2.8 years
 2.9 years
Weighted-average expected volatility59% 58%52% 59%
Weighted-average risk-free rate1.34% 0.87%2.41% 1.34%


The fair value of the TSR PSUs granted during the ninethree months ended September 30,March 31, 2018 and 2017 and 2016 was $5.1$4.2 million and $4.0$5.1 million, respectively. As of September 30, 2017,March 31, 2018, unrecognized compensation cost for TSR PSUs was $5.8$8.4 million and will be amortized through 2019.2020. A summary of the status and activity of TSR PSUs is presented in the following table:
Number of Units1
 Weighted-Average Grant-Date Fair Value
Number of Units1
 Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2016478,510
 $8.09
Not vested, December 31, 2017951,884
 $9.44
Granted473,374
 10.79
321,507
 13.11
Vested
 

 
Forfeited
 

 
Not vested, September 30, 2017951,884
 $9.44
Not vested, March 31, 20181,273,391
 $10.36
1 The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.

Corporate Goals PSUs - The Corporate Goals PSUs have not been finalized by the Compensation Committee, and we have not yet met the requirements of establishing an accounting grant date for them.  This will occur when we communicate the  terms of the awards to the award recipients, which will then trigger the service inception date, the fair value of the awards, and the associated expense recognition period.  As of March 31, 2018, 281,872 Corporate Goals PSUs had been awarded to certain executives.

12.Weighted-Average Shares Outstanding

The following table sets forth the Company's outstanding equity grants which have a dilutive effect on earnings per share:
 Three Months Ended March 31,
 2018 2017
Weighted-average shares outstanding — basic241,751,915
 200,707,891
Potentially dilutive common shares from:   
Stock options347,391
 461,103
TSR PSUs 1
810,128
 
Restricted stock units and stock bonus shares257,463
 140,257
Weighted-average shares outstanding — diluted243,166,897
 201,309,251
1 The number of awards assumes that the associated vesting condition is met at the respective period end based on market prices as of the respective period end. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.

The following potentially dilutive securities outstanding for the periods presented were not included in the respective weighted-average shares outstanding-diluted calculation above:
 Three Months Ended March 31,
 2018 2017
Potentially dilutive common shares from:   
Stock options 1
4,127,834
 4,722,500
TSR PSUs 1,2

 951,884
Corporate Goals PSUs 2,3
281,872
 
Restricted stock units and stock bonus shares 1
398,561
 605,252
Total4,808,267
 6,279,636
1 Potential common shares excluded from weighted-average shares outstanding-diluted calculation as the securities had an anti-dilutive effect on earnings per share.
2 The number of awards reflects the target amount of shares granted. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.
3 Potential common shares excluded from weighted-average shares outstanding-diluted calculation as the securities are considered contingently issuable, and the performance criteria are not considered met as of period end.


13.Income Taxes

We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate, adjusted for the effect of discrete items.

During the three months ended March 31, 2018, the Company concluded it is more likely than not it will realize the benefits of its net deferred tax assets by the end of 2018 as a result of current year ordinary income. This conclusion was based upon the Company’s projection of cumulative positive net income for the three-year period ended December 31, 2018. The release of the valuation allowance is reflected in the Company’s estimated annual effective tax rate since the realization of the Company’s deferred tax assets is supported by current year ordinary income. The Company is projecting a net deferred tax liability with a full release of its beginning valuation allowance by the end of 2018.

The effective tax rates for the three and nine months ended September 30,March 31, 2018 and 2017 were 8% and 2016 were nil.nil, respectively. The effective tax rates for the three and nine months ended September 30,March 31, 2018 and 2017 and 2016 were based upon a full year forecasted tax provision and differsdiffered from the statutory raterates due primarily due to the recognitionrelease of valuation allowanceallowances previously recorded against deferred tax assets. There were no significant discrete items recorded during the three and nine months ended September 30, 2017 and 2016.

As of September 30, 2017,March 31, 2018, we had no liability for unrecognized tax benefits. The Company believes that there are no new items nor changes in facts or judgments that should impact the Company’s tax position.  Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards and would not result in significant interest expense or penalties.  Most of the Company's tax returns filed since August 31, 2011 are still subject to examination by tax authorities. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions, and we are not currently under any state income tax examinations.

No significant uncertain tax positions were identified as of any date on or before September 30, 2017.March 31, 2018.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of September 30, 2017,March 31, 2018, the Company has not recognized any interest or penalties related to uncertain tax benefits.

    Each period, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based uponAs of March 31, 2018, the Company believes it will be able to generate sufficient future taxable income within the carryforward periods and, accordingly, believes that it is more likely than not that its net deferred income tax assets will be fully realized.

14.    Revenue from Contracts with Customers

Sales of oil, natural gas, and NGLs are recognized at the point control of the product is transferred to the customer and collectability is reasonably assured. All of our cumulative losses through September 30, 2017,contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.

 Three Months Ended March 31,
Revenues (in thousands):2018 2017
Oil$116,204
 $29,149
Natural Gas and NGLs31,029
 14,641
 $147,233
 $43,790

Natural Gas and NGLs Sales

Under our natural gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. For these contracts, we have provided a full valuation allowance reducingconcluded the midstream processing entity is our customer. We recognize natural gas and NGLs revenues based on the net realizable benefits.amount of the proceeds received from the midstream processing.

Oil Sales

Our oil sales contracts are generally structured in one of the following ways:

We sell oil production at the wellhead and collect an agreed-upon index price, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received.

We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as Transportation and gathering in our condensed consolidated statements of operations.

Transaction Price Allocated to Remaining Performance Obligations

A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract Balances

Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not typically give rise to contract assets or liabilities under ASC 606, and as of March 31, 2018, we did not have any material contract balances.

Prior-Period Performance Obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three months ended March 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.


14.15.Other Commitments and Contingencies

Volume Commitments

The Company entered into firm sales agreements for its oil production with three counterparties during 2014 and entered into an additional firm sales agreement for its oil production in the third quarter 2017. Deliveries under two of the sales agreements commenced during 2015. Deliveries under the third agreement commenced in 2016. Deliveries under the fourth agreement are expected to commence in the secondfourth quarter of 2018. Pursuant to these agreements, we must deliver specific amounts of oil either from our own production or from oil that we acquire from third parties. If we are unable to fulfill all of our contractual obligations, we may be required to pay penalties or damages pursuant to these agreements. Our commitments over the next five years, excluding the contingent commitment described below, are as follows:
Year ending December 31, Oil Oil
(MBbls) (MBbls)
Remainder of 2017 1,072
2018 4,942
Remainder of 2018 3,436
2019 5,167
 5,167
2020 4,003
 4,003
2021 1,672
 1,672
2022 
Thereafter 
 
Total 16,856
 14,278

During the nine months ended September 30, 2017, the Company incurred deficiency charges of $0.7 million as we were unable to meet all of the obligations during the period. During the thirdfirst quarter of 2017,2018, we were able to meet all of our delivery obligations, and we anticipate that our current gross operated production will continue to meet our future delivery obligations, although this cannot be guaranteed.

In collaboration with several other producers and DCP Midstream, LP ("DCP Midstream"), we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin.  The first agreement includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed by lateduring the third quarter of 2018, although the start-up date is undetermined at this time. Our share of the commitment will require 46.4 MMcf per day to be delivered after the plant in-service date for a period of 7 years. The second agreement also includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed in 2019, although the start-up date is undetermined at this time. Our share of the commitment will require 43.8 MMcf per day to be delivered after the plant in-service date for a period of 7 years. These contractual obligations can be reduced by the collective volumes delivered to the plants by other producers in the D-J Basin that are in excess of such producers' total commitment. We expect that our development plan will support the utilization of this capacity.

Office leases

In September 2016, the Company entered into a new 65-month lease for the Company’s principal office space located in Denver, which commenced in the first quarter of 2017. Rent under the new lease is approximately $62,000 per month. In July 2016, the Company entered into a field office lease in Greeley which requires monthly payments of $7,500 through October 2021. A schedule of the minimum lease payments under non-cancelable operating leases as of September 30, 2017 follows (in thousands):
Year ending December 31, Rent
Remainder of 2017 $208
2018 840
2019 859
2020 878
2021 875
Thereafter 477
Total $4,137


Rent expense for offices leases was $0.2 million for the three months ended September 30, 2017 and 2016, respectively. For the nine months ended September 30, 2017 and 2016, rent expense for office leases was $0.9 million and $0.5 million, respectively.

Litigation

From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business. It is the opinion of management that none of the current matters of contentionproceedings are reasonably likely to have a material adverse impact on ourits business, financial position, results of operations, or cash flows.

Office leases

In September 2016, the Company entered into a 65-month lease for the Company’s principal office space located in Denver, which commenced in the first quarter of 2017. Rent under the lease is approximately $62,000 per month. In July 2016, the Company entered into a field office lease in Greeley which requires monthly payments of $7,500 through October 2021.

Rent expense for offices leases was $0.3 million and $0.4 million for the three months ended March 31, 2018 and 2017, respectively.

Vehicle Leases

The Company has entered into a leasing arrangement for its vehicles used in our normal operations. These leases terminate after four years and are classified as capital leases. The assets associated with these capital leases are recorded within "Other property and equipment, net."

A schedule of the minimum lease payments under non-cancelable capital and operating leases as of March 31, 2018 follows (in thousands):
Year ending December 31: Vehicles Leases Office Leases
Remainder of 2018 $91
 $629
2019 94
 896
2020 94
 916
2021 120
 913
2022 51
 500
Thereafter 
 
Total minimum lease payments $450
 $3,854
Less: Amount representing estimated executory cost (37)  
Net minimum lease payments 413
  
Less: Amount representing interest (59)  
Present value of net minimum lease payments *
 $354
  
* Reflected in the balance sheet as current and non-current obligations of $83 thousand and $271 thousand, respectively, within "Accounts payable and accrued expenses" and "Other liabilities," respectively.

15.16.Supplemental Schedule of Information to the Condensed Consolidated Statements of Cash Flows

The following table supplements the cash flow information presented in the condensed consolidated financial statements for the periods presented (in thousands):
Nine Months Ended September 30,Three Months Ended March 31,
Supplemental cash flow information:2017 20162018 2017
Interest paid$4,796
 $159
$69
 $43
Income taxes paid
 106

 
      
Non-cash investing and financing activities:      
Accrued well costs as of period end$122,387
 $32,299
$66,823
 $81,722
Asset retirement obligations incurred with development activities2,782
 366
223
 882
Asset retirement obligations assumed with acquisitions23,521
 2,046
5
 1,098
Obligations discharged with asset retirements and divestitures(7,023) (3,997)(2,860) (3,287)
   
Net changes in operating assets and liabilities:   
Accounts receivable(8,227) (3,745)
Accounts payable and accrued expenses4,420
 5,293
Revenue payable13,060
 2,486
Production taxes payable5,295
 (4,807)
Other(116) (1,591)
Changes in operating assets and liabilities14,432
 (2,364)


ITEM 2.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion and analysis was prepared to supplement information contained in the accompanying condensed consolidated financial statements and is intended to explain certain items regarding the Company's financial condition as of September 30, 2017March 31, 2018 and its results of operations for the three and nine months ended September 30, 2017March 31, 2018 and 2016.2017.  It should be read in conjunction with the “Selected Financial Data” and the accompanying audited consolidated financial statements and related notes thereto contained in the Annual Report on Form 10-K for the year ended December 31, 20162017 filed with the SEC on February 23, 2017.21, 2018. Unless the context otherwise requires, references to "SRC Energy," "we," "us," "our," or the "Company" in this report refer to the registrant, SRC Energy Inc., and its subsidiaries.

This section and other parts of this Quarterly Report on Form 10-Q contain forward-looking statements that involve risks and uncertainties.  See the “Cautionary Statement Concerning Forward-Looking Statements” elsewhere in this Quarterly Report on Form 10-Q.  Forward-looking statements are not guarantees of future performance, and our actual results may differ significantly from the results discussed in the forward-looking statements.  Factors that might cause such differences include, but are not limited to, those discussed in “Risk Factors.”  We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.

As of January 1, 2017, our natural gas processing agreements with DCP Midstream were modified to allow us to take title to the NGLs resulting from the processing of our natural gas. Based on this, we began reporting reserves, sales volumes, prices, and revenues for natural gas and NGLs separately for periods after January 1, 2017. For periods prior to January 1, 2017, we did not separately report reserves, sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of 2017 with prior periods.

Overview

SRC Energy Inc. is an independent oil and gas company engaged in the acquisition, development, and production of oil, natural gas, and NGLs in the D-J Basin, which we believe to be one of the premier, liquids-rich oil and natural gas resource plays in the United States. It contains hydrocarbon-bearing deposits in several formations, including the Niobrara, Codell, Greenhorn, Shannon, Sussex, J-Sand, and D-Sand. The area has produced oil and natural gas for over fifty years and benefits from established infrastructure including midstream and refining capacity, long reserve life, and multiple service providers.

Our drillingoil and completionnatural gas activities are focused in the Wattenberg Field, predominantly in Weld County, Colorado, an area that covers the western flank of the D-J Basin. Currently, we are focused on the horizontal development of the Codell andformation as well as the three benches of the Niobrara formations,formation, which are all characterized by relatively high liquids content.

In order to maintain operational focus while preserving developmental flexibility, we strive to attain operational control of a majority of the wells in which we have a working interest. We currently operate approximately 90%80% of our proved producing reserves and anticipate operating substantially all of our future net drilling locations. Additionally, our current development plan anticipates that all of our future activities will be concentrated in the Wattenberg Field.

Market Conditions

Market prices for our products significantly impact our revenues, net income, and cash flow.  The market prices for oil, natural gas, and NGLs are inherently volatile.  To provide historical perspective, the following table presents the average annual NYMEX prices for oil and natural gas for each of the last five fiscal years.
Year Ended December 31, Year Ended August 31,Year Ended December 31, Year Ended August 31,
2016 2015 2015 2014 20132017 2016 2015 2015 2014 2013
Average NYMEX prices                    
Oil (per Bbl)$43.20
 $48.73
 $60.65
 $100.39
 $94.58
$50.93
 $43.20
 $48.73
 $60.65
 $100.39
 $94.58
Natural gas (per Mcf)$2.52
 $2.58
 $3.12
 $4.38
 $3.55
$3.00
 $2.52
 $2.58
 $3.12
 $4.38
 $3.55


For the periods presented in this report, the following table presents the Reference Price (derived from average NYMEX prices) as well as the differential between the Reference Price and the prices realized by us.
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended March 31,
2017 2016 2017 20162018 2017
Oil (NYMEX WTI)          
Average NYMEX Price$48.18
 $44.90
 $49.44
 $41.23
$62.89
 $51.91
Realized Price42.37
 35.67
 42.04
 31.47
Differential$(5.81) $(9.23) $(7.40) $(9.76)
Realized Price *56.01
 42.50
Differential *$(6.88) $(9.41)
          
Gas (NYMEX Henry Hub)          
Average NYMEX Price$2.99
 $2.88
 $3.03
 $2.34
$3.00
 $3.01
Realized Price2.35
 2.73
 2.39
 2.18
2.14
 2.66
Differential$(0.64) $(0.15) $(0.64) $(0.16)$(0.86) $(0.35)
          
NGL Realized Price$17.32
 $
 $15.49
 $
$19.15
 $15.94
* Adjusted to include the effect of transportation and gathering expenses.

Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX. The differential between the prices actually received by us at the wellhead and the published indices reflects deductions imposed upon us by the purchasers for location and quality adjustments. The Company's oil production exceeds its firm sales commitments, and the surplus oil production is sold at a reduced differential as compared to our committed volumes. With regard to the sale of oil during the first quarter of 2017, substantially all of the Company's first quarter 2017 oil production was sold to the counterparties of its firm sales commitments. Beginning in the second quarter of 2017, the Company's oil production exceeded its firm sales commitments, and the surplus oil production was sold at a reduced differential as compared to our committed volumes. Relating to the sale of natural gas, prior to January 1, 2017, the price we received included payment for a percentage of the value attributable to the natural gas liquids produced with the natural gas. Beginning in the first quarter of 2017, natural gas liquids and dry natural gas volumes are disclosed separately, and NGL revenues will replace the premium to dry natural gas prices that the Company historically realized on its wet natural gas sales volumes.

There has been significant volatility in the price of oil and natural gas since mid-2014.  During the ninethree months ended September 30, 2017,March 31, 2018, the NYMEX-WTI oil price ranged from a high of $54.48$66.27 per Bbl on January 26, 2018 to a low of $59.20 per Bbl on February 23, 2017 to a low of $42.48 per Bbl on June 21, 2017,9, 2018, and the NYMEX-Henry Hub natural gas price ranged from a low of $2.56$2.55 per MMBtu on February 21, 201712, 2018 to a high of $3.42$3.63 per MMBtu on May 12, 2017.January 29, 2018. As reflected in published data, the price for WTI oil settled at $53.75$60.46 per Bbl on Friday, December 30, 2016.29, 2017.  Comparably, the price of oil settled at $51.67$64.87 per Bbl on Friday, September 29, 2017, a declineMarch 30, 2018, an increase of 4%7% from December 30, 2016.29, 2017. Our revenues, results of operations, profitability and future growth, and the carrying value of our oil and gas properties depend primarily on the prices that we receive for our oil, natural gas, and NGL production.

A decline in oil and natural gas prices will adversely affect our financial condition and results of operations.  Furthermore, low oil and natural gas prices can result in an impairment of the value of our properties and impact the calculation of the “ceiling test” required under the accounting principles for companies following the “full cost” method of accounting.  At September 30, 2017,March 31, 2018, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary.   However, if pricing conditions decline, we may incur a full cost ceiling impairment related to our oil and gas properties in future quarters.


Core Operations

The following table provides details about our ownership interests with respect to vertical and horizontal producing wells as of September 30, 2017:March 31, 2018:
Vertical Wells
Operated WellsOperated Wells Non-Operated Wells TotalsOperated Wells Non-Operated Wells Totals
GrossGross Net Gross Net Gross NetGross Net Gross Net Gross Net
482
 456
 135
 32
 617
 488
296
 285
 163
 48
 459
 333
Horizontal Wells
Operated WellsOperated Wells Non-Operated Wells TotalsOperated Wells Non-Operated Wells Totals
GrossGross Net Gross Net Gross NetGross Net Gross Net Gross Net
208
 194
 191
 33
 399
 227
239
 229
 283
 51
 522
 280

In addition to the producing wells summarized in the preceding table, as of September 30, 2017,March 31, 2018, we were the operator of 4667 gross (36(60 net) horizontal wells in progress, which excludes 1923 gross (14(21 net) wells for which we have only set surface casings. As of September 30, 2017,March 31, 2018, we are participating in 10737 gross (22(9 net) non-operated horizontal wells in progress. The Company is actively conveying its interests in many of the underlying non-operated wells in progress through signed or anticipated agreements.

As we develop our acreage through horizontal drilling, we have an active program for plugging and abandoning the vast majority of the operated vertical wellbores. During the ninethree months ended September 30, 2017,March 31, 2018, we plugged 8645 wells and returned the associated acreage to the property owners.

On May 2, 2017, the Colorado Oil and Gas Conservation Commission issued a Notice to Operators (NTO) to verify the location of all flowlines associated with operated wells and the integrity of those flowlines. The Company has completed all field work associated with the NTO and filed the required paperwork regarding its operations ahead of the June 30, 2017 deadline.

Production

For the three months ended September 30, 2017,March 31, 2018, our average daily production increased to 40,37845,397 BOED as compared to 10,79417,743 BOED for the three months ended September 30, 2016. During the first nine months of 2017, our average net daily production was 30,331 BOED. By comparison, during the nine months ended September 30, 2016, our average production rate was 11,133 BOED.March 31, 2017. As of September 30, 2017, approximatelMarch 31, 2018, approximately 99% oyf99%ofour daily production was from horizontal wells.

Strategy

Our primary objective is to enhance shareholder value by increasing our net asset value, net reserves, and cash flow through development, exploitation, exploration, and acquisitions of oil and gas properties. We intend to follow a balanced risk strategy by allocating capital expenditures to lower risk development and exploitation activities. Key elements of our business strategy include the following:

Concentrate on our existing core area in and around the D-J Basin, where we have significant operating experience.  All of our current wells and our plannedproved undeveloped acreage development isare located either in or adjacent to the Wattenberg Field.Field, and we seek to acquire developed and undeveloped oil and gas properties in the same area. Focusing our operations in this area leverages our management, technical, and operational experience in the basin.

Develop and exploit existing oil and gas properties.  Our principal growth strategy has been to develop and exploit our properties to add reserves.  In the Wattenberg Field, we target three benches of the Niobrara formation as well as the Codell formation for horizontal drilling and production. We believe horizontal drilling is the most efficient way to recover the potential hydrocarbons and consider the Wattenberg Field to be relatively low-risk because information gained from the large number of existing wells can be applied to potential future wells.  There is enough similarity between wells in the Wattenberg Field that the exploitation process is generally repeatable.

ImproveUse the latest technology to maximize returns and improve hydrocarbon recovery through increasedrecovery.  Our development objective for individual well density.  We utilize what we believeoptimization is to be industry best practices in our effortdrill and complete wells with lateral lengths of 7,000' to determine the optimal recovery area10,000'. Utilizing petrophysical and seismic data, a 3-D model is developed for each well. Early horizontalleasehold section to assist in determining optimal wellbore placement, well spacing, and stimulation design. This process is augmented with formation-specific drilling and completion execution designs and coupled with localized production results to implement a continuous improvement philosophy in optimizing the value per acre of our leasehold throughout our development in the Wattenberg Field generally assumed optimal recoveries would be obtained utilizing between 12 and 16 wells per 640-acre section. As horizontal well development has matured, well density assumptions have generally increased beyond 16 wells perprogram.

section depending
Operate in a safe manner and  work in partnership with our surrounding stakeholders.  While our scale of operations has increased significantly, we continue to focus on the specific area of the field being drilled.
Complete selective acquisitions.  Wemaintaining a safe workplace for our employees and contractors. Further, as technology for resource development has advanced, we seek to acquire developedutilize best industry practices to meet or exceed regulatory requirements while reducing our impacts on neighboring communities.  We value our positive relationship with local governing entities and undeveloped oilthe communities in which we operate and gas properties, primarily in the Wattenberg Field.  We generally seek acquisitions that will provide us with opportunities for reserve additions and increased cash flow through production enhancement and additional development and exploratory prospect generation.to continually achieve a status of operator of choice.

Retain control over the operation of a substantial portion of our production. As operator of a majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled.  This allows us to modify our capital spending as our financial resources and underlying lease terms allow and market conditions permit.

Maintain financial flexibility while focusing on operational cost control.  We strive to be a cost-efficient operator and to maintain a relatively low utilization of debt, which enhances our financial flexibility. Our high degree of operational control, as well as our focus on operating efficiencies and short return on investment cycle times, is central to our operating strategy.

Use the latest technology to maximize returns.Acquire and develop assets near established infrastructure  Our development objective for individual well optimization is to drill. We have made acquisitions of contiguous acreage and complete wells with lateral lengths of 7,000' to 10,000'. Utilizing petrophysical and seismic data, a 3-D model is developed for each leasehold section to assist in determining optimal wellbore placement, well spacing, and stimulation design. This process is augmented with formation-specific drilling and completion execution designs and coupled with localized production results to implement a continuous improvement philosophy in optimizing the value per acre of our leasehold throughoutaligned our development program.plans where technically-capable, financially-stable midstream companies have existing assets and plans

for additional investment. We work collaboratively with these companies to proactively identify expansion opportunities that complement our development plans while reducing truck traffic.

Significant Developments

We continue to be opportunistic with respect to acquisition efforts to increase our working interests and drilling location inventory. Further, in an effort to extend the length of laterals and/or increase working interests in our wells, we will continue to enter into land and working interest swaps.

Acquisitions

In September, we completed the second closing of the GC Acquisition. At the second closing, we acquired 335 operated vertical wells and 7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the horizontal wells acquired and September 1, 2017 for the vertical wells acquired. The purchase and sale agreement for the GC Acquisition was signed in May 2016, and the first closing was completed in June 2016. At the second closing, the escrow balance of $18.2 million was released and $11.4 million of that amount was returned to the Company. The total purchase price for the second closing was $31.3 million, composed of cash of $6.8 million and assumed liabilities of $24.5 million. The assumed liabilities included $20.9 million for asset retirement obligations.


In August 2017, we executed a purchase and sale agreement with a private party for the acquisition of approximately 1,000 net acres of developed and undeveloped leasehold and mineral interests, along with the associated production, for a total purchase price of $22.6 million, composed of cash and assumed liabilities.

In March 2017, we acquired developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.0 million, composed of cash and assumed liabilities.

Divestitures

In October 2017, we executed a purchase and sale agreement with a private party resulting in the divestiture of approximately 1,100 net acres and 22 gross (4 net) non-operated wells in progress for $11.6 million. The transaction is expected to close in the fourth quarter of 2017. Additionally, we completed an additional divestiture to a separate private party of 37 operated vertical wells for total consideration of approximately $0.7 million in cash and the assumption by the buyers of $2.3 million in liabilities.

During the nine months ended September 30, 2017, we completed divestitures of approximately 10,700 net undeveloped acres, along with associated production, outside of the Company's core development area for approximately $75.1 million in cash and the assumption by the buyers of $1.7 million in asset retirement obligations and $0.6 million in other liabilities.

Revolving Credit Facility

In September 2017,On April 2, 2018, the Company entered into a second amended and restated credit agreement (the “Restated Credit Agreement”) with certain banks and other lenders, under our revolvingincluding SunTrust Bank, as administrative agent, swingline lender and issuing bank. Among other things, the Restated Credit Agreement, which amends and restates the Company’s prior credit facility (sometimes referred to as the "Revolver") completed their regular semi-annual redeterminationagreement, provides for a maximum credit amount of our borrowing base.  The$1.5 billion, an elected commitment amount of $450 million, and a borrowing base was increased from $225 million to $400of $550 million. The next semi-annual redeterminationCompany is scheduled for April 2018. Duecurrently allowed to borrow up to $450 million under the Restated Credit Agreement, less any outstanding principal balance and letters of credit, approximately $249.5 millionamounts. In addition, the Restated Credit Agreement extends the maturity date of the borrowing base was availablefacility from December 2019 to use for futureApril 2023, reflects certain reductions in interest rates applicable to borrowings as of September 30, 2017, subject to our covenant requirements.under the facility, and adds a $25 million swingline facility.

Drilling and Completion Operations

Our drilling and completion schedule drives our production forecast and our expected future cash flows. We believe that at current drilling and completion cost levels and with currently prevailing commodity prices, we can achieve reasonableattractive well-level rates of return. Should commodity prices weaken further or our costs escalate significantly, our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent. If the well-level internal rate of return is at or below our weighted-average cost of capital, we may choose to delay completions and/or forego drilling altogether. Conversely, if commodity prices move higher, we may choose to accelerate drilling and completion activities.

During the ninethree months ended September 30, 2017,March 31, 2018, we drilled 87 operated 28 operated horizontal wells and completed 87 12 operated horizontal wells.wells. As ofSeptember 30, 2017, March 31, 2018, we are the operator of 4667 gross (36 net)(60 net) horizontal wells in progress, which excludes19 23 gross (14(21 net) horizontal wells for which we have only set surface casings. This activity was funded entirely through cash flows from operations. For 20172018 as a whole, we expect to drill 118 grossdrill 117 gross (100 net) operated horizontal wells primarilyand complete approximately 116 gross (103 net) operated horizontal wells with mid-length and long laterals targeting the Codell and Niobrara formations.

For the ninethree months ended September 30, 2017,March 31, 2018, we participated in the completion of 167 gross (1 net) non-operated horizontal wells. As ofSeptember 30, 2017, March 31, 2018, we are participating in 107 37 gross (22 net)(9 net) non-operated horizontal wells in progress. The Company is actively conveying its interests in many of the underlying non-operated wells in progress through signed or anticipated agreements.

Trends and Outlook

Oil traded at$53.75 $60.46 per Bbl onDecember 30, 2016,29, 2017, but has sincedeclined increased approximately4% 7% as ofSeptember 29, 2017 March 30, 2018 to$51.67. $64.87. Natural gas traded at$3.72 $2.95 per Mcf onDecember 30, 2016,29, 2017, butdeclinedapproximately19% 7% as ofSeptember 29, 2017 March 30, 2018 to $2.73. $3.01. LowerAlthough oil prices have increased in the first quarter of 2018, they continue to be volatile and are out of our control. If oil prices decrease, this could (i) reduce our cash flow which, in turn, could reduce the funds available for exploring and replacing oil and natural gas reserves, (ii) reduce our Revolver borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) reduce the number of oil and gas prospects which have reasonable economic returns, (iv) may cause us to allow leases to expire based upon the value of potential oil and natural gas reserves in relation to the costs of exploration, (v) may result in marginally productive oil and natural gas wells being abandoned as non-commercial, and (vi) may cause ceiling test impairments.

Other factors that will most significantly affect our results of operations include (i) activities on properties that we operate, (ii) the marketability of our production, (iii) the availability and capacity of gathering systems, pipelines, and other midstream infrastructure for our production, (iv) our ability to satisfy our financial and volume commitment obligations, (iv)(v) completion of acquisitions of additional properties and reserves, and (v)(vi) competition from other oil and gas companies.

We utilize what we believe to be industry best practices in our effort to achieve optimal hydrocarbon recoveries.  Currently, our practice is to drill 16 to 24 horizontal wells per 640-acre section depending upon specific geologic attributes and existing vertical wellbore development.  Some operators are testing higher density programs, but we believe that it is too early to determine whether the recoveries justify the additional capital cost.

We have been able to reduce drilling and completion costs due to a combination of optimizing well designs, lower contract rates for drilling rigs, fewer average days to drill, and lower completion costs. This focus on cost reduction has supported well-level economics giving consideration

to the current prices of oil and natural gas. We continue to strive to reduce drilling and completion costs going forward, but as commodity prices improve and industry activity increases, we may experience higher service costs, causing well-level rates of return to be lower.costs.

From time to time, our production has been adversely impacted by high natural gas gathering line pressures. Where it is cost effective, we install wellhead compression to enhance our ability to inject natural gas into the gathering system and, in some instances, install larger gathering lines to help mitigate the impact of high line pressures. Additionally, midstreamMidstream companies that operate the natural gas processing facilities and gathering pipelines in the areaWattenberg Field continue to make significant capital investments to increase the capacity of their systems. While these actions have helpedFrom time to increasetime, our production has been adversely impacted by the lack of processing capacity forresulting in high natural gas processing, we continue to experiencegathering line pressures exceeding system limits primarily due to further growth in field-wide production volumes.pressures.

To address the growing volumes of natural gas production in the D-J Basin, DCP Midstream has announcedinitiated plans for multiple projects including new processing plants, low pressure gathering systems, additional compression, and plant bypass infrastructure. Most notably, in collaboration with DCP Midstream, we and several other producers have agreed to participate insupport the expansion of natural gas gathering and processing capacity in the D-J Basin.through agreements that impose baseline and incremental volume commitments, which we are currently exceeding.  The initial plan includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system, both expected to be completed by lateoperational in the third quarter of 2018. Additionally, through the same framework, all of the parties agreed to a development plan to add another 200 MMcf/d plant in 2019. These agreements impose a baseline and incremental volume commitment which we are currently exceeding.mid-2019.

We have extended the use of oil and water gathering lines to certain production locations. These gathering systems are owned and operated by independent third parties, and we commit specific leases or areas to these systems. We believe that oilthese gathering lines have several benefits, including a) reduced need to use trucks, to gather our oil, thereby reducing truck traffic and noise in and around our production locations, b) potentially lower gathering costs as pipeline gathering tends to be more efficient, c) reduced on-site oil storage capacity, resulting in lower production location facility costs, and d) generally improved community relations. As these gathering lines are currently being expanded, we have experienced and expect to continue to experience some delays in placing our pads on production.

Oil transportation and takeaway capacity has increased with the expansion of certain interstate pipelines servicing the Wattenberg Field. This has reversed the prior imbalance of oil production exceeding the combination of local refinery demand and the capacity of pipelines to move the oil to other markets. We strive to reduce the negative differential that we have historically realized on our oil production depending on transportation commitments, local refinery demand, and our production volumes. Further details regarding posted prices and average realized prices are discussed in "-Market Conditions."

As of September 30, 2017,March 31, 2018, we have identified over 1,1001,700 drilling locations across our acreage position.position in the core of the Wattenberg Field. For 2017,2018, we expect to drill 118 drill 117 gross operated horizontal wells ofwith mostly mid-length and long laterals targeting the Codell and Niobrara zones. We anticipate this drilling and completion program will cost approximately $360between $480 million and $540 million and will lead to a significant increase in production and associated proved developed producing reserves while allowing us to retain significant operational and financial flexibility to reduce or accelerate activity in response to changing economic conditions. Additionally, 2017 drilling and completion expenditures associated with non-operated properties are expectedreserves. We expect our production to be approximately $60 million, whichsomewhat flat over the first half of the year and then to accelerate over the second half of the year as additional natural gas processing capacity is net of capital we expect to recover as describedcompleted in "- Capital Expenditures" below. Full-year 2017the basin. We currently estimate that full-year 2018 production is forecasted to bewill average between 33,00048,000 BOED and 35,000 BOED. Assuming a 2018 development program similar to what the Company has done in 2017, we expect to achieve year-over-year production growth52,000 BOED, with oil making up 47% - 50% of 25% or greater, while funding a majority of our expenditures through internally generated cash flow. production.

Other than the foregoing, we do not know of any trends, events, or uncertainties that have had, during the periods covered by this report, or are reasonably expected to have, a material impact on our sales, revenues, expenses, liquidity, or capital resources.

Results of Operations

Material changes to certain items in our condensed consolidated statements of operations included in our condensed consolidated financial statements for the periods presented are discussed below.

For the three months ended September 30, 2017March 31, 2018 compared to the three months ended September 30, 2016March 31, 2017

For the three months ended September 30, 2017,March 31, 2018, we reported net income of $43.8$65.8 million compared to net lossincome of $19.2$19.9 million during the three months ended September 30, 2016.March 31, 2017. Net income per basic and diluted share was $0.22$0.27 for the three months ended September 30, 2017March 31, 2018 compared to net lossincome per basic and diluted share of $0.10 for the three months ended September 30, 2016.March 31, 2017. Net income per basic share for the three months ended September 30, 2017March 31, 2018 increased by $0.32 primarily due to the ceiling test impairment of $25.5 million incurred during the three months ended September 30, 2016 (whereas no ceiling test impairment was recognized during the three months ended September 30, 2017) and the 295% increase in revenues period over period. Revenues increased during the three months ended September 30, 2017 compared with the three months ended September 30, 2016 due to a 274% increase in production and a 6% increase in realized prices. As of September 30, 2017, we had 1,016 gross producing wells, of which 399 were horizontal, compared with 635 gross producing wells, of which 245 were horizontal, as of September 30, 2016.$0.17.


Oil, Natural Gas, and NGL Production and Revenues - For the three months ended September 30, 2017,March 31, 2018, we recorded total oil, natural gas, and NGL revenues of $103.6$147.2 million compared to $26.2$43.8 million for the three months ended September 30, 2016,March 31, 2017, an increase of $77.4$103.4 million or 295%236%. The following table summarizes key production and revenue statistics:

Three Months Ended September 30, PercentageThree Months Ended March 31, Percentage
2017 2016 Change2018 2017 Change
Production:          
Oil (MBbls) 1
1,726
 517
 234 %2,041
 680
 200 %
Natural Gas (MMcf) 2
7,412
 2,855
 160 %7,719
 3,446
 124 %
NGLs (MBbls) 3
753
 
 nm
MBOE 4
3,715
 993
 274 %
BOED 5
40,378
 10,794
 274 %
NGLs (MBbls) 1
758
 343
 121 %
MBOE 3
4,086
 1,597
 156 %
BOED 4
45,397
 17,743
 156 %
          
Revenues (in thousands):          
Oil$73,144
 $18,451
 296 %$116,204
 $29,149
 299 %
Natural Gas17,402
 7,783
 124 %16,517
 9,179
 80 %
NGLs 3
13,047
 
 nm
NGLs14,512
 5,462
 166 %
$103,593
 $26,234
 295 %$147,233
 $43,790
 236 %
Average sales price:          
Oil$42.37
 $35.67
 19 %
Oil 5
$56.01
 $42.50
 32 %
Natural Gas2.35
 2.73
 (14)%2.14
 2.66
 (20)%
NGLs 3
17.32
 
 nm
BOE$27.89
 $26.42
 6 %
NGLs19.15
 15.94
 20 %
BOE 5
$35.58
 $27.27
 30 %
1"MBbl" "MBbl" refers to one thousand stock tank barrels, or 42,000 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.
2 "MMcf" refers to one million cubic feet of natural gas.
3 For periods prior to January 1, 2017, we did not separately report sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of the two periods presented.
4 "MBOE" refers to one thousand barrels of oil equivalent, which combines MBbls of oil and MMcf of natural gas by converting each six MMcf of natural gas to one MBbl of oil.
54 "BOED" refers to the average number of barrels of oil equivalent produced in a day for the period.
5 Adjusted to include the effect of transportation and gathering expenses.

Net oil, natural gas, and NGL production for the three months ended September 30, 2017March 31, 2018 averaged 40,37845,397 BOED, an increase of 274%156% over average production of 10,79417,743 BOED in the three months ended September 30, 2016.March 31, 2017. From September 30, 2016March 31, 2017 to September 30, 2017,March 31, 2018, our well count increased by 91119 net horizontal wells, growing our reserves and daily production totals. Additionally, our conversion to three stream accounting positively impacted reported production in the current period. The 274%156% increase in production and the 6%30% increase in average sales prices resulted in a significant increase in revenues.


Lease Operating Expenses ("LOE")LOE - Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
Three Months Ended September 30,Three Months Ended March 31,
2017 20162018 2017
Production costs$4,223
 $3,529
$7,714
 $3,473
Workover93
 290
182
 249
Transportation and gathering838
 
Total LOE$5,154
 $3,819
$7,896
 $3,722
      
Per BOE:      
Production costs$1.14
 $3.55
$1.89
 $2.17
Workover0.03
 0.29
0.04
 0.16
Transportation and gathering0.23
 
Total LOE$1.40
 $3.84
$1.93
 $2.33

Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells, and our overall production volumes, and to a lesser extent, on fluctuations in oil field service costs and changes in the production mix of oil and natural gas.costs. During the three months ended September 30, 2017,March 31, 2018, we experienced increased production expense compared tothree months ended September 30, 2016March 31, 2017 due to a 113% 80%

increase in horizontalnet operated wells and a274% 156% increase in production volumes. In addition, in the third quarter, we began delivering under new gathering agreements which resulted in transportation and gathering charges. Unit operating costs benefited from larger volumes of early production on the horizontalhorizontal wells turned to sales duringover the quarterlast twelve months.

Transportation and gathering - During 2017, the Company entered into new gathering agreements which resulted in additionnew transportation and gathering charges. Transportation and gathering was $1.9 million, or $0.45 per BOE, for the three months ended March 31, 2018, compared to $0.3 million, or $0.16 per BOE, for the production from wells turned to sales afterthree months ended March 31, 2017. While reported as an expense, the third quarter of 2016.Company analyzes these charges on a net basis within revenue.

Production taxes - Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. DuringProduction taxes were $13.4 million, or $3.29 per BOE, for the three months ended September 30, 2017, production taxes were $10.1March 31, 2018, compared to $1.5 million, or $2.71 per BOE, compared to $(1.5) million, or $(1.47)$0.92 per BOE, during the prior year period.three months ended March 31, 2017. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were 9.7%9.1% and (5.6)%3.3% for the three months ended September 30,March 31, 2018 and 2017, and 2016, respectively. During the three months ended September 30,March 31, 2017, the production tax rate reflects the significant increase in new production and its impact on severance tax. As discussed in Note 1, during the three months ended September 30, 2016, the Company reduced its estimate for ad valoremproduction taxes based on recent historical experience and additional information received during the period. Based on this analysis, the Company's prior year accruals were reduced, resulting in an approximate $3.6$2.0 million reduction to our production taxes.taxes during the three months ended March 31, 2017. 

DD&A - The following table summarizes the components of DD&A:
Three Months Ended September 30,Three Months Ended March 31,
(in thousands)2017 20162018 2017
Depletion of oil and gas properties$32,944
 $9,273
$36,102
 $12,703
Depreciation and accretion796
 362
979
 526
Total DD&A$33,740
 $9,635
$37,081
 $13,229
      
DD&A expense per BOE$9.08
 $9.70
$9.08
 $8.28

For the three months ended September 30, 2017,March 31, 2018, DD&A was $9.08 per BOE compared to $9.70$8.28 per BOE for the three months ended September 30, 2016.March 31, 2017. The decreaseincrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. This ratio was significantly reduced due to the impairments of our full cost pool that primarily occurred during the first half of 2016 and the increase in our total proved reserves. These impacts were partially offset by recentrecent drilling and completion activities which increased the amortization base. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determinesdetermined the depletion rate.

Full cost ceiling impairment - During the three months ended September 30, 2017, we had no impairment as compared to an impairment of $25.5 million for the three months ended September 30, 2016, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling.


General and Administrative ("G&A") - The following table summarizes G&A expenses incurred and capitalized during the periods presented:
Three Months Ended September 30,Three Months Ended March 31,
(in thousands)2017 20162018 2017
G&A costs incurred$11,002
 $9,993
$12,741
 $10,880
Capitalized costs(2,518) (1,757)(3,141) (2,680)
Total G&A$8,484
 $8,236
$9,600
 $8,200
      
Non-Cash G&A$3,030
 $2,375
$2,796
 $2,675
Cash G&A5,454
 5,861
6,804
 5,525
Total G&A$8,484
 $8,236
$9,600
 $8,200
      
Non-Cash G&A per BOE$0.82
 $2.39
$0.68
 $1.68
Cash G&A per BOE1.47
 5.90
1.67
 3.46
G&A Expense per BOE$2.29
 $8.29
$2.35
 $5.14

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. Total G&A costs of $8.5$9.6 million for the thirdfirst quarter of 20172018 were 3%17% higher than G&A for the same period of 2016.2017. This increase is primarily due to a 32%31% increase in employee headcount from 89105 at September 30, 2016March 31, 2017 to 117138 at September 30, 2017, which was offset by a reduction in professional fees incurred due to decreased deal activity and contract services during 2017.March 31, 2018.

Our G&A expense for the three months ended September 30, 2017March 31, 2018 includes stock-based compensation of $3.0$2.8 million compared to $2.4$2.7 million for the three months ended September 30, 2016. Stock-based compensation is a non-cash charge that is based on the calculated fair value of stock options, performance-vested stock units, restricted share units, and stock bonus shares that we grant for compensatory purposes. For stock options, the fair value is estimated using the Black-Scholes-Merton option pricing model. For performance-vested stock units, the fair value is estimated using the Monte Carlo model. For restricted stock units and stock bonus shares, the fair value is estimated using the closing stock price on the grant date. Amounts are pro-rated over the vesting terms of the award agreements, which are generally three to five years.March 31, 2017.

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the three months ended September 30, 2016March 31, 2017 to the three months ended September 30, 2017March 31, 2018 reflects our overall increase in G&A activity.increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

Commodity derivative gains (losses) - As more fully described in Item 1. Financial Statements – Note 8, Commodity Derivative Instruments, we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the three months ended September 30, 2017,March 31, 2018, we realized a cash settlement gainloss of $0.1$2.1 million, net of previously incurred premiums attributable to the settled commodity contracts. For the prior comparable period, we realized a cash settlementlossof $13.0$119.0 thousand, net of previously incurred premiums attributable to the settled commodity contracts.

In addition, for the three months ended September 30, 2017,March 31, 2018, we recorded an unrealized loss of $2.5$3.7 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the three months ended September 30, 2016,March 31, 2017, we reported an unrealized gain of $0.4$3.5 million. Unrealized gains and losses are non-cash items.

Income taxes - We reported no income tax expense for the three months ended September 30, 2017 or the prior year period. During the three months ended September 30, 2017 and 2016, the effective tax rates were substantially reduced by recognition of a full valuation allowance on the net deferred tax assets. During the three months ended September 30, 2017 and 2016, the effective tax rate differed from the statutory rate primarily due to the recognition of the valuation allowance recorded against deferred tax assets.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. Based on the level of cumulative losses in the prior periods and the level of uncertainty with respect to future taxable income over the period in which the deferred tax assets are deductible, a valuation

allowance has been provided as of September 30, 2017. During the 2016 comparable period, we reached the same conclusion; therefore, a valuation allowance has been provided as of September 30, 2016.

For the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016

For the nine months ended September 30, 2017, we reported net income of $91.7 million compared to net loss of $224.5 million during the nine months ended September 30, 2016. Net income per basic and diluted share was $0.46 for the nine months ended September 30, 2017 compared to net loss per basic and diluted share of $1.36 for the nine months ended September 30, 2016. Net income per basic share for the nine months ended September 30, 2017 increased by $1.82 primarily due to the ceiling test impairment of $215.2 million incurred during the nine months ended September 30, 2016 (whereas no ceiling test impairment was recognized during the nine months ended September 30, 2017) and the 225% increase in revenues period over period. Revenues increased during the nine months ended September 30, 2017 compared with the nine months ended September 30, 2016 due to a 171% increase in production and a 20% increase in realized prices. As of September 30, 2017, we had 1,016 gross producing wells, of which 399 were horizontal, compared with 635 gross producing wells, of which 245 were horizontal, as of September 30, 2016.

Oil, Natural Gas, and NGL Production and Revenues - For the nine months ended September 30, 2017, we recorded total oil, natural gas, and NGL revenues of $222.4 million compared to $68.5 million for the nine months ended September 30, 2016, an increase of $154.0 million or 225%. The following table summarizes key production and revenue statistics:
 Nine Months Ended September 30, Percentage
 2017 2016 Change
Production:     
Oil (MBbls)3,668
 1,552
 136%
Natural Gas (MMcf)17,122
 8,991
 90%
NGLs (MBbls) 1
1,758
 
 nm
MBOE8,280
 3,050
 171%
    BOED30,331
 11,133
 172%
      
Revenues (in thousands):     
Oil$154,232
 $48,838
 216%
Natural Gas40,945
 19,616
 109%
NGLs 1
27,242
 
 nm
 $222,419
 $68,454
 225%
Average sales price:     
Oil$42.04
 $31.47
 34%
Natural Gas2.39
 2.18
 10%
NGLs 1
15.49
 
 nm
BOE$26.86
 $22.44
 20%
1 For periods prior to January 1, 2017, we did not separately report sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of the two periods presented.

Net oil, natural gas, and NGL production for the nine months ended September 30, 2017 averaged 30,331 BOED, an increase of 172% over average production of 11,133 BOED in the nine months ended September 30, 2016. From September 30, 2016 to September 30, 2017, our well count increased by 91 net horizontal wells, growing our reserves and daily production totals. Additionally, our conversion to three stream accounting positively impacted reported production in the current period. The 171% increase in production and the 20% increase in average sales prices resulted in a significant increase in revenues.


LOE - Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
 Nine Months Ended September 30,
 2017 2016
Production costs$12,511
 $14,464
Workover$497
 $499
Transportation and gathering$886
 $
Total LOE$13,894
 $14,963
    
Per BOE:   
Production costs$1.51
 $4.74
Workover0.06
 0.16
Transportation and gathering0.11
 
Total LOE$1.68
 $4.90

Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells and our overall production volumes and, to a lesser extent, on fluctuations in oil field service costs and changes in the production mix of oil and natural gas.During thenine months ended September 30, 2017, we experienceddecreasedproduction expense compared to thenine months ended September 30, 2016primarily due to significantly less expense related to environmental remediation and regulatory compliance projects during 2017 and theconsolidation of our operations into a more central geographic operating area. This decrease was partially offset by transportation and gathering charges resulting from new gathering agreements. Unit operating costs benefited from larger volumes of early production on the 87 horizontal wells turned to sales during thenine months ended September 30, 2017in addition to the production on wells turned to sales after thethirdquarter of2016.

Production taxes - Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. Production taxes were $21.0 million, or $2.54 per BOE, for the nine months ended September 30, 2017, compared to $2.5 million, or $0.82 per BOE, for the nine months ended September 30, 2016. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were 9.4% and 3.7% for the nine months ended September 30, 2017 and 2016, respectively. During the nine months ended September 30, 2017, the Company adjusted its estimates for production taxes to reflect a significant increase in new production. As discussed in Note 1, during the nine months ended September 30, 2016, the Company reduced its estimate for ad valorem taxes, resulting in an approximate $3.6 million reduction to our production taxes.

DD&A - The following table summarizes the components of DD&A:
 Nine Months Ended September 30,
(in thousands)2017 2016
Depletion of oil and gas properties$71,389
 $31,981
Depreciation and accretion2,007
 1,020
Total DD&A$73,396
 $33,001
    
DD&A expense per BOE$8.86
 $10.82

For the nine months ended September 30, 2017, DD&A was $8.86 per BOE compared to $10.82 per BOE for the nine months ended September 30, 2016. The decrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. This ratio was significantly reduced due to the impairments of our full cost pool that primarily occurred during the first half of 2016 and the increase in our total proved reserves. These impacts were partially offset by recent drilling and completion activities which increased the amortization base. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determined the depletion rate.

Full cost ceiling impairment - During the nine months ended September 30, 2017, we had no impairment as compared to an impairment of $215.2 million for the nine months ended September 30, 2016, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling.

G&A - The following table summarizes G&A expenses incurred and capitalized during the periods presented:
 Nine Months Ended September 30,
(in thousands)2017 2016
G&A costs incurred$32,018
 $27,944
Capitalized costs(7,729) (4,745)
Total G&A$24,289
 $23,199
    
Non-Cash G&A$8,390
 $7,285
Cash G&A15,899
 15,914
Total G&A$24,289
 $23,199
    
Non-Cash G&A per BOE$1.01
 $2.39
Cash G&A per BOE1.92
 5.22
G&A Expense per BOE$2.93
 $7.61

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. Total G&A costs of $24.3 million for the third quarter of 2017 were 5% higher than G&A for the same period of 2016. This increase is primarily due to a 32% increase in employee headcount from 89 at September 30, 2016 to 117 at September 30, 2017, which was offset by a reduction in professional fees incurred due to decreased deal activity and contract services during 2017.

Our G&A expense for the nine months ended September 30, 2017 includes stock-based compensation of $8.4 million compared to $7.3 million for the nine months ended September 30, 2016.

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the nine months ended September 30, 2016 to the nine months ended September 30, 2017 reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

Commodity derivatives - As more fully described in Item 1. Financial Statements – Note 8,13, Commodity Derivative Instruments,Income Taxes, we use commodity contracts to help mitigatereported income tax expense of $5.8 million for the risks inherent in the price volatility of oil and natural gas. For the ninethree months ended September 30, 2017, we realized a cash settlement loss of $26.0 thousand, net of previously incurred premiums attributableMarch 31, 2018 as compared to the settled commodity contracts. For the prior comparable period, we realized a cash settlement gain of $2.9 million.

In addition, for the nine months ended September 30, 2017, we recorded an unrealized gain of $2.4 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the nine months ended September 30, 2016, we reported an unrealized loss of $6.5 million. Unrealized gains and losses are non-cash items.

Income taxes - We reported no income tax expense for the nine months ended September 30, 2017 or thecomparable prior year period. As explained in more detail in the "-Income taxes" section above, during the nine months ended September 30, 2017 and 2016, theThe effective tax rates were substantially reduced by recognition of a full valuation allowance onfor the net deferred tax assets. During the ninethree months ended September 30,March 31, 2018 and 2017 and 2016, the effective tax rate differed from the statutory raterates due primarily due to the recognitionrelease of the valuation allowanceallowances previously recorded against deferred tax assets.

Liquidity and Capital Resources

Historically, our primary sources of capital have been net cash provided by cash flow from operations, proceeds from the sale of properties, the sale of equity and debt securities, and borrowings under bank credit facilities.  Our primary use of capital has been for the exploration, development, and acquisition of oil and gas properties.  Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us.

We believe that our capital resources, including cash flows from operating activities, cash on hand, and amounts available under our revolving credit facility and cash flow from operating activities will be sufficient to fund our planned capital expenditures and operating expenses for the next

twelve months. To the extent actual operating results differ from our anticipated results, available borrowings under our credit facility are reduced, or we experience other unfavorable events, our liquidity could be adversely impacted.  Our liquidity would also be affected if we increase our capital expenditures or complete one or more additional acquisitions. Terms of future financings may be unfavorable, and we cannot assure investors that funding will be available on acceptable terms.

As operator of the majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled. This allows us to modify our capital spending as our financial resources allow and market conditions support. Additionally, our relatively low utilization of debt enhances our financial flexibility as it provides a potential source of future liquidity while currently not overly burdening us with restrictive financial covenants and mandatory repayment schedules.

Sources and Uses

Our sources and uses of capital are heavily influenced by the prices that we receive for our production. During the nine months ended September 30, 2017, the NYMEX-WTI oil price ranged from a high of $54.48 per Bbl on February 23, 2017 to a low of $42.48 per Bbl on June 21, 2017, while the NYMEX-Henry Hub naturalOil and gas price ranged from a low of $2.56 per MMBtu on February 21, 2017 to a high of $3.42 per MMBtu on May 12, 2017. These markets will likely continue to be volatile in the future. To deal with the volatility in commodity prices, we maintain a flexible capital investment program and seek to maintain a high operating interest in our leaseholds with limited long-term capital commitments. This enables us to accelerate or decelerate our activities quickly in response to changing industry environments.


At September 30, 2017,March 31, 2018, we had cash, and cash equivalents, and restricted cash of $21.3$71.7 million, $80.0$550.0 million outstanding on our Senior 2025 Notes, and a $150.0 millionno balance outstanding balance under our revolving credit facility. Our sources and (uses) of funds for the ninethree months ended September 30,March 31, 2018 and 2017 and 2016 are summarized below (in thousands):
Nine Months Ended September 30,Three Months Ended March 31,
2017 20162018 2017
Net cash provided by operations$142,817
 $33,193
$127,681
 $29,358
Capital expenditures(383,483) (582,149)(105,633) (85,034)
Net cash provided by other investing activities95,265
 5,979
728
 70,689
Net cash (used in) provided by equity financing activities(517) 542,901
Net cash provided by (used in) debt financing activities148,628
 (2,666)
Net increase (decrease) in cash and equivalents$2,710
 $(2,742)
Net cash provided by (used in) equity financing activities431
 (431)
Net cash used in debt financing activities(236) 
Net increase in cash, cash equivalents, and restricted cash$22,971
 $14,582

Net cash provided by operating activities was $142.8$127.7 million and $33.2$29.4 million for the ninethree months ended September 30,March 31, 2018 and 2017, and 2016, respectively.respectively. The increase in cash from operating activities reflects the increase in realized commodity prices and production.

NetNet cash provided by other investing activities was $95.3$0.7 millionand $6.0$70.7 millionfor the ninethree months ended September 30, March 31, 2018and2017, and 2016, respectively. For the nine months ended September 30, 2017, we receivedrespectively, which were primarily comprised of proceeds from the sale of oil and gas properties and other of $77.0 million, and $18.2 million was released from an escrow account relating to an acquisition. For the nine months ended September 30, 2016, we received proceeds from the sale of oil and gas properties of $24.2 million; these inflows were offset by net cash deposited in escrow of $18.2 million.

During the nine months ended September 30, 2017, we received cash proceeds from borrowing $170.0 million under the Revolver and used cash proceeds from a divestiture to repay $20.0 million of these borrowings.properties.

Credit Facility

The Revolver has a maturity date of December 15, 2019.  The agreement was most recently amended in September 2017.April 2, 2023.  The Revolver has a maximum loan commitment of $500 million;$1.5 billion; however, the maximum amount that we can borrowavailable to be borrowed at any one time is subject to a borrowing base limitation, which stipulates that we may borrow up to the lesserleast of the aggregate maximum loancredit amount, the aggregate elected commitment, or the borrowing base.  The borrowing base can increase or decrease based upon the value of the collateral, which secures any amounts borrowed under the Revolver.  The value of the collateral will generally be derived with reference to the estimated discounted future net cash flows from our proved oil and natural gas reserves. The collateral includes substantially all of our producing wells and developed oil and gas leases.


As a result of entering into the Restated Credit Agreement with certain banks and other lenders oregular semi-annual redetermination of our borrowing base on September 27, 2017,n April 2, 2018, the borrowing base was increased from $225400 million to $400 million.550 million; however, our elected commitment amount was $450 million. As of September 30, 2017,March 31, 2018, there was a$150.0 millionoutstanding no principal balance outstanding and $0.5 million in letters of credit outstanding, leaving $249.5399.5 million available to us for future borrowings. After giving effect to the Restated Credit Agreement, the amount available to us for future borrowings increased to $449.5 million. The next semi-annual redetermination is scheduled for AprilNovember 2018. Interest on the Revolver accrues at a variable rate. The interest rate pricing grid contains a graduatedprovides for an escalation in applicable margin forbased on increased utilization.utilization of the Revolver.

The Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. In particular, the Company must not (a) permit its ratio of total funded debt to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0 as of the endlast day of any fiscal quarter or (b) as of the last day of any fiscal quarter permit its ratio of current ratio,assets to current liabilities, each as defined in the agreement, to be less than 1.0 to 1.0.1.0as of the last day of any fiscal quarter.

2025 Senior Notes

On June 14, 2016,In November 2017, the Company issued $80$550 million aggregate principal amount of the6.25% Senior Notes in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021.December 1, 2025. Interest on the 2025 Senior Notes accrues at 9%6.25% and began accruing on June 14, 2016.November 29, 2017. Interest is payable on June 151 and December 151 of each year.year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 (the "Indenture")November 29, 2017 and will beare guaranteed on a senior unsecured basis by anythe Company’s existing and future subsidiaries of the Company that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility.Revolver. At any time prior to December 14, 2018,1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to 100% of the Make-Whole Priceprincipal amount plus an Applicable Premium (as defined in the Indenture) andplus accrued and unpaidunpaid interest.  On and after December 14, 2018,1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at the redemption price atequal to a specified percentage of the principal amount of the redeemed notes (104.50%(104.688% for 2018, 102.25%2020, 103.125% for 2019,2021, 101.563% for 2022, and 100.0%100% for 20202023 and thereafter, during the twelve-month period beginning on December 141 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018,1, 2020, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the 2025 Senior

Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to 109.00%106.25% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.

The Indenture contains covenants that restrict the Company’s ability and the ability of any restrictedcertain of its subsidiaries to, among other things:restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities.  These covenants are subject to a number of exceptions and qualifications.

Capital Expenditures

Capital expenditures for drilling and completion activities totaled $159.5$111.0 million and $383.0$93.2 million for the three and nine months ended September 30,March 31, 2018 and 2017, respectively. The following table summarizes our capital expenditures for oil and gas properties (in thousands):
Three Months Ended March 31,
Three Months Ended September 30, 2017 Nine Months Ended September 30, 20172018 2017
Capital expenditures for drilling and completion activities   $111,009
 $93,176
Operated$94,971
 $290,717
Non-operated64,561
 92,311
Total159,532
 383,028
   
Acquisitions of oil and gas properties and leasehold*56,835
 89,677
9,284
 27,493
Capitalized interest, capitalized G&A, and other5,718
 17,514
13,346
 5,323
Accrual basis capital expenditures**$222,085
 $490,219
$133,639
 $125,992
*Acquisitions of oil and gas properties and leasehold reflects the full purchase price of our various acquisitions which includes non-cash additions for liabilities assumed in the transaction such as asset retirement obligations.
**Capital expenditures reported in the condensed consolidated statement of cash flows are calculated on a cash basis, which differs from the accrual basis used to calculate the capital expenditures.

The year-to-date non-operated capital expenditures are driven by the Company's decision to participate in several wells located within our core operating area. The Company is actively conveying its interests in many of the underlying non-operated wells in progress through signed or anticipated agreements. If successful, the Company anticipates recovering approximately 50% of the year-to-date non-operated capital expenditures.

During the ninethree months ended September 30, 2017,March 31, 2018, we drilled 8728 operated horizontal wells and compturleted 87ned 12 operated horizontal wells.wells to sales. As of September 30, 2017,March 31, 2018, we are the operator of 4667 gross (36(60 net) horizontal wells in progress.which excludes 23 gross (21 net) wells for which we have only set surface casings. All of the wells in progress at March 31, 2018 are scheduled to commence production beforeDecember 31, 2019. This activity was funded entirely through cash flows from operations.

For the ninethree months ended September 30, 2017,March 31, 2018, we have participated in 12344 gross (23(10 net) non-operated horizontal wells.

Capital Requirements

Our level of exploration, development, and acreage expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows, development results, and downstream infrastructure and commitments, among other factors. Our primary need for capital will be to fund our anticipated drilling and completion activities and any other acquisitions that we may complete during the remainder of 2017.2018.

We anticipate that our 20172018 drilling and completion capital expenditures for operated wells will be approximately $360cost between $480 million and $540 million for the year. However, should commodity prices and/or economic conditions change, we can reduce or accelerate our drilling and completion activities, which could have a material impact on our anticipated capital requirements. Additionally, 2017 drilling and completion expenditures associated with non-operated properties are expected to be approximately $60 million, which is net of capital we expect to recover as described in "- Capital Expenditures" above. Assuming a 2018 development program similar to what the Company has done in 2017, we expect to achieve year-over-year production growth of 25% or greater, while funding a majority of our expenditures through internally generated cash flow.

For the near term, we believe that we have sufficient liquidity to fund our needs through cash on hand, cash flow from operations, and additional borrowings available under our revolving credit facility.  However, should this not meet all of our long-term needs, we may need to raise additional funds to drill new wells through the sale of our securities, from third parties willing to pay our share of drilling and completing wells, or from other sources.  We may not be successful in raising the capital needed to drill or acquire oil or natural gas wells. We may seek to raise funds in capital markets transactions from time to time if we believe market conditions to be favorable.

Oil and Natural Gas Commodity Contracts

We use derivative contracts to help protect against the variability in cash flows created by short-term price fluctuations associated with the sale of future oil and natural gas production.  At September 30, 2017,March 31, 2018, we had open positions covering 1.32.8 million barrels of oil and 8,9844,125 MMcf of natural gas. We do not use derivative instruments for speculative purposes.

Our commodity derivative instruments may include but are not limited to “collars,” “swaps,” and “put” positions. Our derivative strategy, including the volumes and commodities covered and the relevant strike prices, is based in part on our view of

expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in our credit facility.

During the ninethree months ended September 30, 2017,March 31, 2018, we reported an unrealized commodity activity gainloss of $2.4$3.7 million.  Unrealized gainslosses are non-cash items.  We also reported a realized loss of $26.0 thousand,$2.1 million, representing the cash settlement of commodity contracts settled during the period, net of previously incurred premiums attributable to the settled commodity contracts.

At September 30, 2017,March 31, 2018, we estimated that the fair value of our various commodity derivative contracts was a net liability of $1.2$11.6 million. See Item 1. Financial Statements – Note 9, Fair Value Measurements, for a description of the methods we use to estimate the fair values of commodity derivative instruments.

Non-GAAP Financial Measures

In addition to financial measures presented on the basis of accounting principles generally accepted in the United States of America ("US GAAP"), we present certain financial measures which are not prescribed by US GAAP ("non-GAAP"). The following is a summary of the measure we currently report.

Adjusted EBITDA

We use "adjusted EBITDA," a non-GAAP financial measure, for internal managerial purposes because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed in the table below from net income (loss) in arriving at adjusted EBITDA. We exclude those items because they can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures, and the method by which the assets were acquired. Adjusted EBITDA is not a measure of financial performance under US GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, and it should not be viewed as a liquidity measure or indicator of cash flows reported in accordance with US GAAP.net income. We believe that adjusted EBITDA is a widely used in our industry as a measure of operating performance and may also be used by investors to measure our ability to meet debt covenant

requirements. However, our definition of adjusted EBITDA may not be fully comparable to measures with similar titles reported by other companies. We define adjusted EBITDA as net income (loss) adjusted to exclude the impact of the items set forth in the table below (amounts in thousands):
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended March 31,
2017 2016 2017 20162018 2017
Adjusted EBITDA:          
Net income (loss)$43,848
 $(19,241) $91,664
 $(224,490)
Net income$65,796
 $19,880
Depreciation, depletion, and accretion33,740
 9,635
 73,396
 33,001
37,081
 13,229
Full cost ceiling impairment
 25,453
 
 215,223
Income tax expense
 5
 
 106
Stock-based compensation3,030
 2,374
 8,390
 7,285
Stock-based compensation expense2,796
 2,675
Mark-to-market of commodity derivative contracts:          
Total (gain) loss on commodity derivatives contracts2,383
 (407) (2,324) 3,617
5,781
 (3,379)
Cash settlements on commodity derivative contracts544
 486
 778
 5,137
(1,555) 81
Interest income, net of interest expense(16) (11) (47) (176)(9) (11)
Income tax expense5,811
 
Adjusted EBITDA$83,529
 $18,294
 $171,857
 $39,703
$115,701
 $32,475

Critical Accounting Policies

We prepare our condensed consolidated financial statements and the accompanying notes in conformity with US GAAP, which requires management to make estimates and assumptions about future events that affect the reported amounts in the condensed consolidated financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management discusses the development, selection, and disclosure of each of the critical accounting policies.

There have been no significant changes to our critical accounting policies and estimates or in the underlying accounting assumptions and estimates used from those disclosed in the "Management’s Discussion and Analysis of Financial Condition and Results of Operations" section of the Annual Report on Form 10-K filed with the SEC on February 23, 201721, 2018 and in the financial

statements and accompanying notes contained in that report. Item 1. Financial Statements – Note 1, Organization and Summary of Significant Accounting Policies, to the accompanying condensed consolidated financial statements included elsewhere in this report provides information regarding recently issued accounting pronouncements.



Cautionary Statement Concerning Forward-Looking Statements

This report contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as "believes," "expects," "anticipates," "intends," "plans," "estimates," "should," "likely," or similar expressions indicate forward-looking statements. Forward-looking statements included in this report include statements relating to future production, future capital expenditures and projects, the adequacy and nature of future sources of financing, possible future impairment charges, midstream capacity issues, future differentials, future production relative to volume commitments, and the closing and effect of proposed transactions.

The identification in this report of factors that may affect our future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty.

See "Risk Factors" in this report and in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 20162017 filed with the SEC on February 23, 201721, 2018 for a discussion of risk factors that affect our business, financial condition, and results of operations. These risks include, among others, those associated with the following:

declines in oil and natural gas prices;
operating hazards that adversely affect our ability to conduct business;
uncertainties in the estimates of proved reserves;
the effect of seasonal weather conditions and wildlife and plant species restrictions on our operations;
our ability to fund, develop, produce, and acquire additional oil and natural gas reserves that are economically recoverable;
our ability to obtain adequate financing;
the effect of local and regional factors on oil and natural gas prices;
incurrence of ceiling test write-downs;
our inability to control operations on properties that we do not operate;
the availability and capacity of gathering systems, pipelines, and other midstream infrastructure for our production;
the strength and financial resources of our competitors;
our ability to complete, and the effect of, pending and planned transactions;
our ability to successfully identify, execute, and effectively integrate acquisitions;
the effect of federal, state, and local laws and regulations;
the effects of, including costs to comply with, environmental legislation or regulatory initiatives, including those related to hydraulic fracturing;
our ability to market our production;
the effects of local moratoria or bans on our business;
the effect of environmental liabilities;
the effect of the adoption and implementation of statutory and regulatory requirements for derivative transactions;
changes in U.S. tax laws;
our ability to satisfy our contractual obligations and commitments;
the amount of our indebtedness and our ability to maintain compliance with debt covenants;
the effectiveness of our disclosure controls and our internal controls over financial reporting;
the geographic concentration of our principal properties;
our ability to protect critical data and technology systems;
the availability of water for use in our operations; and
the risks and uncertainties described and referenced in "Risk Factors."



ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

Commodity Price Risk - Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. The volatility of oil prices affects our results to a greater degree than the volatility of natural gas prices, as approximately 71% and 69%79% of our revenue during the three and nine months ended September 30, 2017, respectively,March 31, 2018 was from the sale of oil. A $5 per barrel change in our realized oil price would have resulted in a $8.6 million and $18.3$10.2 million change in revenues during the three and nine months ended September 30, 2017, respectively,March 31, 2018, a $0.25 per Mcf change in our realized natural gas price would have resulted in a $1.9 million and $4.3 million change in our natural gas revenues for the three and nine months ended September 30, 2017, respectively,March 31, 2018, and a $5 per barrel change in our realized NGL price would have resulted in a $3.8 million and $8.8 million change in our NGL revenues for the three and nine months ended September 30, 2017, respectively.March 31, 2018.

During the three months ended September 30, 2017,March 31, 2018, the price of oil, natural gas, and NGLs increased relative to the thirdfirst quarter of 2016.2017.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil, natural gas, and NGL prices include the levels of demand and supply for oil (in global or local markets), the establishment of and compliance with production quotas by oil exporting countries, weather conditions which influence the demand for natural gas, the price and availability of alternative fuels, the strength of the US dollar compared to other currencies, and overall economic conditions. It is impossible to predict future oil, natural gas, and NGLs prices with any degree of certainty. Sustained weakness in oil, natural gas, and NGL prices may adversely affect our financial condition and results of operations and may also reduce the amount of oil, natural gas, and NGL reserves that we can produce economically. Any reduction in our oil, natural gas, and NGL reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities.  Similarly, any improvements in oil, natural gas, and NGL prices can have a favorable impact on our financial condition, results of operations, and capital resources.

We attempt to mitigate fluctuations in short-term cash flow resulting from changes in commodity prices by entering into derivative positions on a portion of our expected oil and natural gas production.  Under the Revolver, we can use derivative contracts to cover up to 85% of expected proved developed producing production as projected in our semi-annual reserve report, generally over a period of two years.  We do not enter into derivative contracts for speculative or trading purposes. As of September 30, 2017,March 31, 2018, we had open oil and natural gas derivatives in a net liability position with a fair value of $1.2$11.6 million.  A hypothetical upward shift of 10% in the NYMEX forward curve of oil and natural gas prices would decrease the fair value of our position by $1.4$10.8 million. A hypothetical downward shift of 10% in the NYMEX forward curve of oil and natural gas prices would increase the fair value of our position by $1.2$3.2 million. A summary of our open positions as of September 30, 2017 is set forth in Item 1. Financial Statements - Note 8, Commodity Derivative Instruments.

Interest Rate Risk - At September 30, 2017,March 31, 2018, we had $150 millionno in debt outstanding under our revolving credit facility.  Interest on our credit facility accrues at a variable rate, based upon either the Prime Rate or LIBOR plus an applicable margin.  During the ninethree months ended September 30, 2017,March 31, 2018, we incurred no interest at an annualized rate of 3.3%. Weexpense on our revolving credit facility. When we have balances outstanding under the revolving credit facility, we are exposed to interest rate risk on the credit facility if the variable reference rates increase. If interest rates increase, our monthly interest payments would increase and our available cash flow would decrease.  We estimate that if market interest rates increased or decreased by 1%, the change to our interest payments in each of the three and nine months ended September 30, 2017March 31, 2018 would have changed by $0.3 million and $0.4 million, respectively.be insignificant.

Under current market conditions, we do not anticipate significant changes in prevailing interest rates for the next year, and we have not undertaken any activities to mitigate potential interest rate risk due to restrictions imposed by the Revolver.

Counterparty Risk - As described in "- Commodity Price Risk" above, we enter into commodity derivative agreements to mitigate short-term price volatility.  These derivative financial instruments present certain counterparty risks.  We are exposed to potential loss if a counterparty fails to perform according to the terms of the agreement. The failure of any of the counterparties to fulfill their obligations to us could adversely affect our results of operations and cash flows.  We do not require collateral or other security to be furnished by counterparties.  We seek to manage the counterparty risk associated with these contracts by limiting transactions to well capitalized, well established, and well-known counterparties that have been approved by our senior officers.  There can be no assurance, however, that our practice effectively mitigates counterparty risk. 

We believe that our exposure to counterparty risk increaseddecreased slightly during the thirdfirst quarter of 20172018 as the amounts due tofrom us fromto counterparties has increased.



ITEM 4.CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act") as of the end of the period covered by this report on Form 10-Q (the "Evaluation Date").  Based on such evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the Evaluation Date, our disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


PART II

Item 1.Legal Proceedings

Except as disclosed in Note 1415 to the accompanying condensed consolidated financial statements, during the quarter, there were no material developments regarding legal matters, which were previously described under Item 3, Legal Proceedings, of the Annual Report on Form 10-K filed with the Securities and Exchange Commission on February 23, 2017.21, 2018. This information should be considered carefully together with other information in this report and other reports and materials we file with the SEC.

Item 1A.Risk Factors

We face many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity, and the trading price of our common stock are described under Item 1A, Risk Factors, of the Annual Report on Form 10-K filed with the SEC on February 23, 2017.21, 2018. This information should be considered carefully together with other information in this report and other reports and materials that we file with the SEC.

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

Purchases of equity securities by the Company
Period Total Number of Shares Purchased Average Price Paid per Share
July 1, 2017 - July 31, 2017 (1)
 
 $
August 1, 2017 - August 31, 2017 (1)
 5,167
 $7.68
September 1, 2017 - September 30, 2017 (1)
 3,235
 $7.95
   Total 8,402
  
Period Total Number of Shares Purchased Average Price Paid per Share
January 1, 2018 - January 31, 2018 (1)
 25,339
 $8.86
February 1, 2018 - February 28, 2018 (1)
 25,772
 $9.19
March 1, 2018 - March 31, 2018 (1)
 25,906
 $9.42
   Total 77,017
  

(1) Pursuant to statutory minimum withholding requirements, certain of our employees exercised their right to "withhold to cover" as a tax payment method for the vesting and exercise of certain shares. These elections were outside of any publicly announced repurchase plan.

Item 3.Defaults Upon Senior Securities

None.

Item 4.Mine Safety Disclosures

Not applicable

Item 5.Other Information

On August 18, 2017, the Company amended its bylaws to, among other things, include advance notice provisions pursuant to which a shareholder seeking to propose a candidate for election as director or other business at a meeting of the Company’s shareholders is required to provide advance notice of the proposal to the Company. This notice must contain specified information regarding the shareholder and the proposal and must generally be provided (i) in the case of an annual meeting, not earlier than the 120th day, and not later than the 90th day, prior to the first anniversary of the preceding year’s annual meeting and (ii) in the case of a special meeting, not earlier than the 90th day, and not later than the 80th day, prior to such meeting. Subject to certain possible exceptions set forth in the amended and restated bylaws, notice of proposals to be made at the Company’s 2018 annual meeting of shareholders must be provided no earlier than February 15, 2018 and no later than March 19, 2018.None

Item 6.        Exhibits

Exhibit
Number
 Exhibit
3.2
31.1 
31.2 
32.1 
99.1
101.INS 
XBRL Instance Document
101.SCH XBRL Taxonomy Extension Schema
101.CAL XBRL Taxonomy Extension Calculation Linkbase
101.DEF XBRL Taxonomy Extension Definition Linkbase
101.LAB XBRL Taxonomy Extension Label Linkbase
101.PRE XBRL Taxonomy Extension Presentation Linkbase
   
   
* Filed herewith
** Furnished herewith



SIGNATURES

Pursuant to the requirements of Section 13 or 15(a) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized on the 1st2nd day of November, 2017.May, 2018.

 SRC Energy Inc.
  
 /s/ Lynn A. Peterson
 
Lynn A. Peterson, President and Chief Executive Officer
(Principal Executive Officer)
  
 /s/ James P. Henderson
 
James P. Henderson, Executive Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
  
 /s/ Jared C. Grenzenbach
 
Jared C. Grenzenbach, Vice President and Chief Accounting Officer
(Principal Accounting Officer)